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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)

x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED December 31, 2025
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD OF _________ TO _________.

Commission File Number: 001-41489
ENCORE ENERGY CORP.
(Exact name of registrant as specified in its charter)

British Columbia, Canada |  | Not Applicable
State or other jurisdiction of incorporation or organization |  | (I.R.S. Employer Identification No.)

One Galleria Tower
13355 Noel Rd, Suite 1700
Dallas, Texas 75240
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: 361-239-2025
Securities registered pursuant to Section 12(b) of the Act:

Title of each class | Trading Symbol | Name of each exchange on which registered
Common Shares, no par value | EU | The Nasdaq Capital Market LLC TSX Venture Exchange

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☐ Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | o | Accelerated filer | o | Non-accelerated filer | x
|  | Smaller reporting company | x | Emerging growth company | o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the common shares of the registrant held by non-affiliates of the registrant as of June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, was $523.2 million based upon the closing price reported for such date on the Nasdaq Capital Market, LLC.
As of March 28, 2026, there were 194,216,153 shares of the registrant’s no par value common shares, the registrant’s only outstanding class of voting securities, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the registrant’s 2026 Annual Meeting of Shareholders are incorporated by reference in Part III of this Annual Report on Form 10-K.

Auditor Firm Id: | 185 | Auditor Name: | KPMG LLP | Auditor Location: | Houston, Texas, United States |

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TABLE OF CONTENTS

| Cautionary Note Regarding Forward Looking Statements | 3
PART I |
Item 1. | Business and Properties | 1
Item 1A. | Risk Factors | 47
Item 1B. | Unresolved Staff Comments | 69
Item 1C. | Cybersecurity | 69
Item 2. | Properties | 70
Item 3. | Legal Proceedings | 70
Item 4. | Mine Safety Disclosures | 70
PART II |
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 70
Item 6. | [Reserved] |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 80
Item 7A | Quantitative and Qualitative Disclosures about Market Risk | 92
Item 8. | Financial Statements and Supplementary Data | F-1
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 42
Item 9A. | Controls and Procedures | 42
Item 9B. | Other Information | 43
Item 9C | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 44
PART III |
Item 10. | Directors, Executive Officers and Corporate Governance | 45
Item 11. | Executive Compensation | 45
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 45
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 45
Item 14. | Principal Accountant Fees and Services | 45
PART IV |
Item 15. | Exhibits and Financial Statement Schedules | 46
Item 16. | Form 10-K Summary | 48
| Signatures | 48

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When we use the terms “enCore Energy Corp.,” “we,” “us,” “our,” or the “Company,” we are referring to enCore Energy Corp. and its subsidiaries, unless the context otherwise requires. Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Cautionary Statement Regarding Forward-Looking Statements” section of this document for an explanation of these types of assertions. We have included technical terms important to an understanding of our business under “Glossary of Terms” at the end of this section.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (“Annual Report”) and information incorporated by reference herein, contains forward-looking statements and forward-looking information within the meaning of the Private Securities Litigation Reform Act of 1995 and applicable Canadian securities legislation that are subject to risks and uncertainties. Forward-looking statements and information can generally be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “continue,” “plans,” “maintains,” “projects,” and similar terminology or variations (including negative variations) of such words and phrases or statements. Forward-looking statements and information are not historical facts, are made as of the date of this Annual Report, and include, but are not limited to, statements regarding discussions of results from operations (including, without limitation, statements about the Company’s opportunities, strategies, competition, expected activities, revenues from existing contracts and expenditures, including as the Company pursues its business plan, the adequacy of the Company’s available cash resources and other statements about future events or results), performance (both operational and financial), including operational expansion, statements regarding the ability to complete, and the timing of completion of a distribution of common shares of Verdera (as defined below) and ability to complete, to shareholders of the Company and business prospects, expectations regarding continuation of delineation drilling adjacent to existing wellfields continuing, future business plans and opportunities and statements as to management’s expectations with respect to, among other things, the activities contemplated in this Annual Report.
Forward-looking statements and information may include, but are not limited to, statements with respect to:

| ● | the Company’s future financial and operational performance; |  |
| ● | the sufficiency of the Company’s current working capital, anticipated cash flow or its ability to raise necessary funds; |  |
| ● | the anticipated amount and timing of work programs; |  |
| ● | our expectations with respect to future exchange rates; |  |
| ● |  | the estimated cost of and availability of funding necessary for sustaining capital; |
| ● |  | forecast capital and non-operating spending, including changes in cost as a result of changes in trade restrictions, for example: the imposition of tariffs; |
| ● | the Company’s plans and expectations for its property, exploration, development, extraction and community relations operations; |  |
| ● | the use of available funds; |  |
| ● | expectations regarding the process for and receipt of regulatory approvals, permits and licenses under governmental and other applicable regulatory regimes, including U.S. government policies towards domestic uranium supply; |  |
| ● | expectations about future uranium market prices, production costs and global uranium supply and demand; |  |
| ● | expectations regarding holding physical uranium for long-term investment; |  |
| ● | the establishment of mineral resources on any of the Company’s current or future mineral properties (other than the Company’s properties that currently have established mineral resource estimates); |  |
| ● | future royalty and tax payments and rates; |  |
| ● | expectations regarding possible impacts of litigation and regulatory actions; and
| ● | the completion of reclamation activities at former mine or extraction sites. |  |

Such forward-looking statements reflect the Company’s current views with respect to future events, based on information currently available to the Company and are subject to and involve certain known and unknown risks, uncertainties, assumptions and other factors which may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed in or implied by such forward-looking statements and information. The forward-looking statements and information in this Annual Report are based on material assumptions, including the following:
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| ● | our budget, including expected levels of exploration, evaluation, development, extraction and operational activities and costs, as well as assumptions regarding market conditions and other factors upon which we have based our income and expenditure expectations; |
| ● | assumptions regarding the timing and use of our cash resources; |
| ● | our ability to, and the means by which the Company can, raise additional capital to advance other exploration and evaluation objectives; |
| ● | our operations and key suppliers of essential services; |
| ● | our employees, contractors and subcontractors will be available to continue operations; |
| ● | our ability to obtain all necessary regulatory approvals, permits and licenses for our planned activities under governmental and other applicable regulatory regimes; |
| ● | our expectations regarding the demand for and supply of uranium, the outlook for long-term contracting, changes in regulations, public perception of nuclear power, and the construction of new and ongoing operation of existing nuclear power plants; |
| ● | our expectations regarding spot and long-term prices and realized prices for uranium; |
| ● | our expectations that our holdings of physical uranium will be helpful in securing project financing and/or in securing long- term uranium supply agreements in the future; |
| ● |  | our expectations regarding tax rates, currency exchange rates, and interest rates;
| ● | our decommissioning and reclamation obligations and the status and ongoing maintenance of agreements with third parties with respect thereto; |
| ● | our mineral resource estimates, and the assumptions upon which they are based;
| ● | our, and our contractors’, ability to comply with current and future environmental, safety and other regulatory requirements and to obtain and maintain required regulatory approvals; and |
| ● | our operations are not significantly disrupted by political instability, nationalization, terrorism, sabotage, pandemics, social or political activism, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, equipment or infrastructure failure, labor shortages, transportation disruptions or accidents, or other development or exploration risks. |

Some of the risks and uncertainties that could cause actual results to differ materially from any future results expressed in or implied by the forward-looking statements and information in this Annual Report include, among others, the following:
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● | our history of negative operating cash flows and our ability to develop or maintain positive cash flow from our extraction activities and the ability to obtain additional financing, if needed, in connection with the implementation of business and strategic plans; |
● | risks associated with our expansion-by-acquisition strategy; |
● | our properties do not contain mineral reserves and some of our properties, projects and facilities may not be economic within a reasonable time period or at all; |
● | reliance on key personnel, contractors and experts; |
● | conflicts of interest of our directors and officers; |
● | risks associated with exploration of, development of, and extraction from mineral properties; |
● | our reliance on third party drilling contractors, including an increased risk of loss, including weather related risks or underutilization of drilling rigs; |
● | risks inherent to mineral exploration and extraction; |
● | the commercial viability of economic extraction of minerals from uranium deposits; |
● | the subjectiveness and uncertainty of estimations of mineral resources; |
● | future mineral extraction estimates may not be achieved; |
● | estimates of commodity prices used in preliminary economic assessments may never be realized; |
● | requirements to obtain or retain key permits to advance or achieve extraction; |
● | involvement of external groups, including Native American tribes or non-governmental organizations, in the permitting process; |
● | challenges to title of our mineral property interests; |
● | our ability to attract, retain, train, motivate, and develop skilled employees; |
● | existing competition and geopolitical changes in the competitive landscape; |
● | public opinion and perception of nuclear energy; |
● | volatility in market prices of uranium; |
● | applicable laws, regulations and standards, including environmental protection laws and regulations; |
● | our ability to raise equity or obtain debt financing, including obtaining additional financing on acceptable terms when needed; |
● | accuracy of extraction, capital and operating cost estimates; |
● | ability of novel methods for extraction to yield anticipated results; |
● | the need for technical innovation and risk of obsolescence; |
● | availability of a public market for uranium, including global demand and supply; |
● | changes and uncertainty in United States trade policy, tariff and import/export regulations; |
● | risks related to our operations on federal lands, including possible designation of national monuments or withdrawal of permits; |
● | risks related to our Alta Mesa joint venture; |
● | taxation implications of United States holders if the Company is a passive foreign investment company; |
● | potential dilution if we issue additional common shares, no par value (the “common shares”) or securities convertible into common shares; |
● | price volatility of our common shares; |
● | our expectation to not declare or pay dividends; |
● | reliance on information technology systems, and cybersecurity risks; |
● | the time and resources necessary to comply with corporate governance practices and securities rules and regulations in the United States and Canada; |
● | our management’s ability to maintain effective internal controls; |
● | our remediation plan and ability to remediate the material weaknesses in our internal controls over financial reporting; |
● | potential lack of access to enforcement of civil liabilities against the Company or its directors and officers; |
● | our ability to protect our proprietary data, technology and intellectual property; |
● | changes in climate conditions; and |
● | other risks included under the heading “Risk Factors” in this Annual Report. |

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While forward-looking statements and information reflect our good faith beliefs, they are not guarantees of future performance. Any forward-looking statements and information are based on estimates and assumptions only as of the date of this Annual Report, and the Company undertakes no obligation to update or revise any forward-looking statement or information to reflect information, events, results, circumstances or the occurrence of unanticipated events, except as required by applicable laws. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factors on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements or information.
CAUTIONARY NOTE TO U.S. RESIDENTS CONCERNING DISCLOSURE OF MINERAL RESOURCES
Effective as of January 1, 2025, the Company no longer qualifies as a foreign private issuer as defined in Rule 405 under the Securities Act of 1933, as amended (the “Securities Act”) and Rule 3b-4 under the Securities Exchange Act of 1934, (the “Exchange Act”) and therefore has become a domestic issuer required to file this Annual Report pursuant to Sections 13 or 15(d) of the Exchange Act and to report its financial results under United States generally accepted accounting principles (“U.S. GAAP”).
All mineral estimates constituting mining operations that are material to our business or financial condition included in this Annual Report, and in the documents incorporated by reference herein, have been prepared in accordance with subpart 1300 of Regulation S-K (collectively, “S-K 1300”) and are supported by initial assessments prepared in accordance with the requirements of S-K 1300. S-K 1300 provides for the disclosure of: (i) “Inferred Mineral Resources,” which investors should understand have the lowest level of geological confidence of all Mineral Resources and thus may not be considered when assessing the economic viability of a mining project and may not be converted to a Mineral Reserve (as defined below); (ii) “Indicated Mineral Resources,” which investors should understand have a lower level of confidence than that of a “Measured Mineral Resource” and thus may be converted only to a “Probable Mineral Reserve,” and (iii) Measured Mineral Resources, which investors should understand have sufficient geological certainty to be converted to a “Proven Mineral Reserve” or to a “Probable Mineral Reserve.” Investors are cautioned not to assume that all or any part of Measured Mineral Resources or Indicated Mineral Resources will ever be converted into Mineral Reserves as defined by S-K 1300. Investors are cautioned not to assume that all or any part of an Inferred Mineral Resource exists or is economically or legally mineable, or that an Inferred Mineral Resource will ever be upgraded to a higher category.
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GLOSSARY OF TERMS
In this Annual Report, the following terms have the meanings set forth herein:
Mineral Resource Definitions:
“Indicated Mineral Resource” is that part of a Mineral Resource for which quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. As used in this subpart, the term adequate geological evidence means evidence that is sufficient to establish geological and grade or quality continuity with reasonable certainty. The level of geological certainty associated with an Indicated Mineral Resource is sufficient to allow a Qualified Person to apply Modifying Factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. An Indicated Mineral Resource has a lower level of confidence than the level of confidence of a Measured Mineral Resource and may only be converted to a Probable Mineral Reserve.
“Inferred Mineral Resource” is a component of Mineral Resource for which quantity and grade or quality are estimated on the basis of limited geological evidence and sampling; where the term limited geological evidence means evidence that is only sufficient to establish that geological and grade or quality continuity is more likely than not. The level of geological uncertainty associated with an Inferred Mineral Resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Because an Inferred Mineral Resource has the lowest level of geological confidence of all Mineral Resources, which prevents the application of the modifying factors in a manner useful for evaluation of economic viability, an Inferred Mineral Resource may not be considered when assessing the economic viability of a mining project and may not be converted to a Mineral Reserve.
“Measured Mineral Resource” is that part of a Mineral Resource for which quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a Measured Mineral Resource is sufficient to allow a qualified person to apply modifying factors, as defined in this section, in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit. Because a Measured Mineral Resource has a higher level of confidence than the level of confidence of either an Indicated Mineral Resource or an Inferred Mineral Resource, a Measured Mineral Resource may be converted to a Proven Mineral Reserve or to a Probable Mineral Reserve.
“Mineral Resource” is a concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. When determining the existence of a Mineral Resource, a Qualified Person, as defined by this section, must be able to estimate or interpret the location, quantity, grade or quality continuity, and other geological characteristics of the Mineral Resource from specific geological evidence and knowledge, including sampling; and conclude that there are reasonable prospects for economic extraction of the Mineral Resource based on an initial assessment, as defined in this section, that he or she conducts by qualitatively applying relevant technical and economic factors likely to influence the prospect of economic extraction.
Additional Defined Terms:
“Alta Mesa Technical Report(s)” means the S-K 1300 technical report summary entitled “Alta Mesa Uranium Project, Brooks County, Texas, USA, S-K 1300 Technical Report Summary” and “Alta Mesa Uranium Project, Brooks County, Texas, USA, National Instrument 43-101, Technical Report” dated February 19, 2025 and effective December 31, 2024 prepared by Stuart Bryan Soliz, PG of SOLA Project Services, LLC.
“Development Stage Issuer” is an issuer that is engaged in the preparation of mineral reserves for extraction on at least one material property.
“Dewey Burdock Technical Report(s)” means the S-K 1300 technical report entitled “Dewey Burdock Project, South Dakota, USA, S-K 1300 Technical Report Summary” and “Dewey Burdock Project South Dakota, USA, National Instrument 43-101, Preliminary Economic Assessment Technical Report” dated January 6, 2025, and effective as of October 8, 2024 prepared by Stuart Bryan Soliz, PG of SOLA Project Services, LLC.
“Exploration Stage Issuer” is an issuer that has no material property with Mineral Reserves disclosed.
“Exploration Stage Property” is a property that has no Mineral Reserves disclosed.
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“Gas Hills Technical Report” means the S-K 1300 technical report entitled “Technical Report Preliminary Economic Assessment Gas Hills Uranium Project, Fremont and Natrona Countie s,” dated February 4, 2025, and effecti ve December 31, 2024, prepared by Chris McDowell, P.G. and Ray Moores, P.E. of Western Water Consultants d/b/a WWC Engineering.
“GT” means grade-thickness, a measure referring to the concentration of a mineral in Ore and the width of the Ore body.
“Ion-exchange” or “IX” means a reversible chemical reaction that swaps ions between a solid and a solution. In the case of the Company’s operation, the ion exchange occurs in a bed of strong base anionic polystyrene resin beads contained in a vessel or column.
“ISR” means In Situ Recovery (literally, ‘in place’ recovery) describes rocks or formations that have not been moved from their original position (also known as in situ leach or ISL).
“Mesteña Grande Technical Report(s)” means the S-K 1300 technical report summary entitled “Mesteña Grande Uranium Project, Brooks and Jim Hogg Counties, Texas, USA, S-K 1300 Technical Report Summary, Initial Assessment” and “Mesteña Grande Uranium Project, Brooks and Jim Hogg Counties, Texas, USA, National Instrument 43-101, Preliminary Economic Assessment,” dated February 19, 2025 and effective December 31, 2024 prepared by Stuart Bryan Soliz, PG of SOLA Project Services.
“Mineralization” means, in exploration, a reference to a notable concentration of metals and their associated mineral compounds, or a specific mineral, within a body of rock.
“Modifying Factors” are the factors that a qualified person must apply to Indicated and Measured Mineral Resources and then evaluate in order to establish the economic viability of Mineral Reserves. A qualified person must apply and evaluate modifying factors to convert Measured and Indicated Mineral Resources to Proven and Probable Mineral Reserves. These factors include but are not restricted to: mining; processing; metallurgical; infrastructure; economic; marketing; legal; environmental compliance; plans, negotiations, or agreements with local individuals or groups; and governmental factors. The number, type and specific characteristics of the modifying factors applied will necessarily be a function of and depend upon the mineral, mine, property, or project.
“Production Area Authorization” or “PAA” is a formal government approval allowing for extraction or production of uranium from a specific area. Production Areas (“PAs”) represent a collection of wellfields for which baseline data, monitoring requirements, and restoration criteria have been established, for development of a Wellfield Hydrologic Data Package that will be submitted to regulatory authorities for mining approval.
“Probable Mineral Reserve” is the economically mineable part of an Indicated Mineral Resource, and in some circumstances, a Measured Mineral Resource. The confidence in the Modifying Factors applying to a Probable Mineral Reserve is lower than that applying to a Proven Mineral Reserve.
“Proven Mineral Reserve” is the economically mineable part of a Measured Mineral Resource. A Proven Mineral Reserve implies a high degree of confidence in the Modifying Factors.
“PFN” is a modern geologic wireline logging method known as Prompt Fission Neutron. PFN is considered a direct measurement of true uranium concentration (% U) and is used to verify the in-situ grades of mineral intercepts previously reported by gamma logging. PFN logging is accomplished by a down-hole probe in much the same manner as standard gamma logs, only, in the case of PFN logging, only the mineralized interval is logged.
“Qualified Person” or “QP” means an individual who:
a.is an engineer or geoscientist with a university degree, or equivalent accreditation, in an area of geoscience, or engineering, relating to mineral exploration or mining;
b.has at least five years of experience in mineral exploration, mine development or operation or mineral project assessment, or any combination of these, that is relevant to his or her professional degree or area of practice;
c.has experience relevant to the subject matter of the mineral project and the technical report;
d.is in good standing with a recognized professional association;
e.in the case of a professional association in a foreign jurisdiction to Canada, has a membership designation that requires attainment of a position of responsibility in their profession that requires the exercise of independent judgment; and requires:
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•favorable confidential peer evaluation of the individual’s character, professional judgement, experience, and ethical fitness; or
•a recommendation for membership by at least two peers and demonstrated prominence or expertise in the field of mineral exploration or mining.
“South Texas Uranium Project Technical Report” means the S-K 1300 technical report entitled “Technical Report on the South Texas Integrated Uranium Projects, Texas, USA,” dated February 15, 2025, and effective December 31, 2024, prepared by Chris McDowell, P.G. and Ray Moores, P.E. of Western Water Consultants d/b/a WWC Engineering.
“TCEQ” means the Texas Commission on Environmental Quality.
“U 3 O 8” is a standard chemical formula commonly used to express the natural form of uranium mineralization. U represents uranium and O represents oxygen. U 3 O 8 is contained in “yellowcake” or “uranium concentrate” accounting for 70% to 90% by weight.
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Part I
Item 1. Business and Properties
Our Company
enCore Energy Corp., America’s Clean Energy Company™, was incorporated on October 30, 2009, under the Laws of British Columbia and is a reporting issuer in all of the provinces and territories of Canada. As of January 1, 2025, the Company ceased to be a “foreign private issuer” and has become a “domestic issuer.” As of December 31, 2024, the Company filing status was a large, accelerated filer within the meanings under the Exchange Act. As of December 31, 2025, the Company’s filing status was a non-accelerated filer within the meanings under the Exchange Act. As a result, the Company must comply with the filing deadlines and disclosure obligations of a domestic issuer and non-accelerated filer as set forth in the Exchange Act. This classification impacts the timing of our periodic filings, internal control assessments, and other regulatory requirements. The Company’s common shares are listed on The Nasdaq Capital Market LLC (“Nasdaq”) and the TSX Venture Exchange (“TSX-V”) under the trading symbol EU.
The Company is an “Exploration Stage Issuer” as defined by S-K 1300, as it has not established proven or probable Mineral Reserves, through the completion of a pre-feasibility or feasibility study for any of our uranium projects as required by the SEC is defined as a Development Stage Issuer. Even though we commenced extraction of uranium at our Rosita Uranium Project and our Alta Mesa Uranium Project, the Company remains classified as an Exploration Stage Issuer and will continue to remain an Exploration Stage Issuer until such time as Proven or Probable Mineral Reserves have been established at one of our uranium projects.
The Company is focused on extracting domestic uranium within the United States. The Company only utilizes the proven ISR technology to provide necessary fuel for the generation of clean, reliable, and carbon-free nuclear energy. In 2024, the Company commenced uranium extraction at the Rosita Central Processing Plant (“CPP”) in South Texas, becoming one of only three uranium extraction operations in the United States and the first in Texas in 10 years. In June 2024, the Company commenced uranium extraction at the Alta Mesa CPP in South Texas. enCore’s strategy is to build uranium extraction capacity by developing and placing into operation a series of uranium extraction facilities in South Texas, followed by a future pipeline of exploration projects in South Dakota and Wyoming, becoming a leading supplier of domestic uranium to fuel a growing demand for clean energy generation using nuclear power.
The Company has set forth key objectives we believe have positioned and will continue to position enCore to quickly respond to the ever-changing global factors, achieve strategic expansions, and build on its adaptability while strengthening the Company’s financial health. These objectives are as follows:
Commenced and Expanded Uranium Extraction at the Alta Mesa Project
Utilizing the extraction-ready CPP in South Texas, the Company has implemented a strategy that it anticipates will continue to build value and phased growth. In the second quarter of 2024, the Company commenced uranium extraction operations at its Alta Mesa CPP, and as a result, becoming one of only a handful of companies in the world with more than one operational uranium extraction operation. In 2025, through the expansion of CPP and wellfield capacity, the Company has increased uranium extraction over 100% compared to the 2024 results. The Company is focused on a long-term strategy of being a supplier of choice for a nuclear industry that is experiencing sustainable growth for the first time in over 45 years.
Streamlined Operations and Rationalized Asset Base
Successful execution is critical, especially in an industry where talent and timing are essential to our success. Adapting swiftly to favorable market conditions is a priority. In December 2023, the Company sold 30% of the Alta Mesa Project to Boss Energy Limited (“Boss”) in the form of a Joint Venture for $60 million. Additionally, Boss invested directly in the Company an additional $10 million. The Company intends to continue to rationalize its asset base through the execution of non-core asset divestment while strengthening our financial position and increasing financial resources in a non-dilutive way. We have demonstrated our ability to derive substantial value for our shareholders from our non-core assets by using different approaches to divestment. The Company currently holds several non-core conventional projects available for acquisition. Lastly, the Company continues to optimize operations to improve extraction results and manage costs effectively.
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M ergers and Acquisitions
Since December 2020, we have demonstrated, through four significant transactions, our intent is to drive growth and provide value for our shareholders through select, accretive merger and acquisition (M&A) activity that complements our own organic growth.
Contract and Sales Strategy Formalization
The Company will continue to leverage its strong baseload contracting strategy and industry reputation as a reliable multi-facility domestic supplier to ensure that our operating assets are able to create revenue regardless of market conditions. As the Company increases uranium extraction from its South Texas facilities, we expect to grow our contract portfolio through the addition of new contracts. The Company will continue to focus on adding new multi-year, hybrid, market-based contracts to maximize profits while protecting against price declines. The Company believes this strategy should provide robust returns on uranium extraction while ensuring a base level of income to support continued operations during market declines over the next decade.
About In-Situ Recovery (ISR), Technology
ISR is a minimally invasive, environmentally friendly, and economically competitive way of extracting minerals from the ground. It has proven to be a successful method of extracting uranium, and due to its cost efficiency, provides an economically viable means of extracting lower grade uranium deposits that might not justify the cost of conventional open pit or underground mining. In addition to significantly lower capital and operating costs, ISR operates without the open pits, waste dumps, or tailings associated with conventional mining and milling. These factors result in uranium extraction that is more environmentally responsible in a faster, more cost-efficient permitting, development and remediation process. ISR extracts uranium from the ground with minimal surface impact. When reclamation is completed, the surface is returned to its original state and use.
ISR is highly regulated in the United States. While some ISR operations in other jurisdictions use harsh chemicals such as sulfuric acid to remove uranium from the ore body, enCore uses a lixiviant comprised of only oxygen and sodium bicarbonate (common baking soda) in the native groundwater to extract uranium at a low pH with significantly less environmental impacts.
ISR is normally most effective in sandstone-hosted deposits within a portion of the aquifer that the government has already exempted from protection as an underground source of drinking water due to its mineral content such as uranium, radium, and other minerals. An ISR wellfield is developed using a series of production patterns comprised of a further series of injection and recovery wells. Injection wells introduce the lixiviant described above to the uranium bearing sandstone. As the lixiviant is injected through the uranium-bearing sandstone, the uranium is solubilized by the oxygen in the lixiviant, and the uranium-bearing lixiviant is carried in solution through the sandstone to the recovery well. Recovery wells, equipped with submersible pumps, recover the uranium-bearing lixiviant out of the sandstone and lift it to the surface. The uranium-bearing lixiviant is then pumped into a surface collection system to be transferred to the IX system. Surrounding the production patterns is a network of monitor wells used to observe groundwater chemistry and hydrology to assure there are no impacts to adjacent underground sources of drinking water. The combination of the production patterns and the monitor well network constitute what is called a wellfield.
After the uranium-bearing lixiviant reaches the IX system, it flows through a bed of IX resin where the uranium is removed from the lixiviant and loaded onto IX resin beads. This process is very similar to how a water softener works. The barren lixiviant is returned to the wellfield, where it is refortified with oxygen and sodium bicarbonate and reinjected into the uranium-bearing sandstone. A small portion, approximately 1% of the total volume, of the barren lixiviant is held back from reinjection. This is called a “process bleed,” and it is intended to create a hydraulic sink in the wellfield to contain lixiviant within production patterns.
When the IX resin loads to capacity with uranium it is regenerated, using a salt solution rich in sodium bicarbonate, in the exact same manner as done for a water softener. This process is called “elution.” Elution produces a uranium-rich eluant that is transferred from the ion exchange system to the precipitation system. Using a series of additions of hydrogen peroxide, acid, and sodium hydroxide, the uranium is precipitated from the eluant and a uranium, “yellowcake,” slurry is created. It is then filtered and washed in a filter press and transferred to the drying system. Drying systems at the Company’s processing facilities use a low-temperature, zero emission, rotary vacuum drying system, the same equipment used for producing pharmaceuticals. Once dried the yellowcake is packaged into 55-gallon drums that are grouped into
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shipping lots. Each shipping lot is then transported to a North American conversion facility where it is weighed, sampled, and inventoried. This is the point at which the Company sells its product to its customers.
When the uranium orebody within an ISR wellfield is depleted, the Company is required to clean up the groundwater to regulatory standards using reverse osmosis technology. Once the government approves the groundwater restoration work, the injection, recovery and monitor wells are plugged and abandoned, and the surface infrastructure is removed. The site is then surveyed for residual contamination that may need to be removed, and the wellfield is returned to its prior use. At this point, the land and groundwater are once again suitable for all the same uses as prior to mining efforts.
The use of ISR technology in the US has a documented strong environmental record. Several wellfields have been restored and released, with the former wellfields now indistinguishable from the adjacent unimpacted land. The US government, in several public documents, has concluded that there have been no impacts to underground sources of drinking water by ISR uranium extraction or restoration.
Corporate Information
enCore was incorporated on October 30, 2009, under the Business Corporations Act (British Columbia) (the “BCBCA”) under the name “Dauntless Capital Corp.” The Company’s name was changed to “Tigris Uranium Corp.” on September 2, 2010, and changed to “Wolfpack Gold Corp.” on May 15, 2013. On August 15, 2014, the Company’s name was changed to “enCore Energy Corp.”
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The following organizational chart illustrates enCore’s principal subsidiaries as at the date of this Annual Report.
Notes:
*POI = Place of incorporation or legal organization
*PPB= Principal place of business
*Green = Dissolved January 31, 2026.
The principal offices of the Company are located at One Galleria Tower, 13355 Noel Rd, Suite 1700, Dallas, TX 75240. The Company’s registered and records office is located at Suite 1200, 750 West Pender Street, Vancouver, British Columbia, V6C 2T8.
Competition
The uranium industry is highly competitive, and our competition includes larger, more established companies with longer operating histories that not only explore for and produce uranium but also market uranium and other products on a regional, national or worldwide basis. Due to their greater financial and technical resources, we may not be able to acquire additional uranium projects in a competitive bidding process involving such companies.
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Geopolitical uncertainty
Geopolitical uncertainty driven by the Russian invasion of Ukraine has led many governments and utility providers to re-examine supply chains and procurement strategies reliant on nuclear fuel supplies coming out of, or through, Russia. Sanctions, restrictions, and an inability to obtain insurance on cargo have contributed to transportation and other supply chain disruptions between producers and suppliers. As a result of this and coupled with multiple years of declining uranium production globally, uranium market fundamentals are shifting from an inventory driven market to one more driven by production. The Prohibiting Russian Uranium Imports Act (H.R. 1042) which was signed into law in May 2024, prohibits the importation of unirradiated, low-enriched uranium produced in the Russian Federation or by a Russian entity, with temporary waivers until January 1, 2028, in certain circumstances, after which the ban will be in effect until December 31, 2040.
While we have limited direct business exposure in areas with current conflict, such as Ukraine or Iran, military actions globally and any resulting sanctions or tariffs could adversely affect the global economy, as well as further disrupt the supply chain. A major disruption in the global economy and supply chain could have a material adverse effect on our business, prospects, financial condition, results of operations, and cash flows. The extent and duration of military action, sanctions, tariffs, and resulting market and/or supply disruptions are impossible to predict but could be substantial, and our management continues to monitor these events closely.
Employees and Human Capital
As of December 31, 2025, 168 people were employed on a full-time basis and approximately 83 individuals provided services on a contractual basis, principally through our drilling rig contractors, all of whom were located in the U.S. Our Company is committed to attracting and retaining talented and experienced individuals to manage and support our operations. We engage in a variety of learning and development opportunities with our employees, including ongoing training, continuing education courses, workshops and seminars and membership in professional organizations relating to employees’ areas of expertise. We strive to fill employment openings through internal promotions or transfers of qualified employees, as appropriate.
Available Information
The Company’s website address is www.encoreuranium.com and the Company’s filings with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports, are available free of charge on our website as soon as reasonably practicable after such materials are filed or furnished electronically with the SEC. Additional information about the Company can be found on our website, however, such information is neither incorporated by reference nor included as part of this or any other report or information filed with or furnished to the SEC. From time to time we may use our website as a distribution channel for material company information.
The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Canadian securities authorities also maintain an internet site (www.sedarplus.ca) that contains reports, circulars, annual information statements and other information regarding the Company.
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Our Mineral Properties
enCore controls key mineral properties within the United States, in Texas, South Dakota, Wyoming and New Mexico. As of December 31, 2025, enCore owns three of the current 10 licensed and constructed ISR CPPs in the United States, with all existing facilities located in the business-friendly, energy-centric state of Texas. Our plants’ operations are designed and permitted to process uranium from a mix of satellite plants and primary sources within south Texas. During the years ended December 31, 2025 and 2024, the Company extracted approximately 700,000 and 300,000, respectively, of U 3 O 8 from its Alta Mesa Uranium Project and its South Texas Integrated ISR Project. See the Summary of Properties below for additional information.
Property Location Map
Summary of Properties
South Texas Integrated ISR Project (Rosita CPP)
The South Texas Integrated ISR Project is an Exploration Stage Property, as defined by S-K 1300, which consists of five project areas: the Rosita Central Processing Plant (“Rosita CPP”), Butler Ranch Uranium ISR Project (“Butler Ranch”), Upper Spring Creek - Brevard Area ISR Uranium Project (“USC – Brevard or Brevard”), Upper Spring Creek - Brown Area ISR Uranium Project (“USC – Brown or Brown”), and Rosita South Cadena ISR Project (“RS – Cadena or Cadena”). For a more detailed discussion of the South Texas Integrated ISR Project see the section titled “Material Properties,” below for this project.
Alta Mesa Uranium Project, Texas
The Alta Mesa Uranium Project (“Alta Mesa”) is an Exploration Stage Property, as defined by S-K 1300, and is a fully licensed and constructed ISR project and central processing facility, located on over 4,597 acres of private land in the state of Texas. For a more detailed discussion of the Alta Mesa Uranium Project see the section titled “Material Properties,” below for this project.
Mesteña Grande Uranium Project, Texas
The Mesteña Grande Uranium Project (“Mesteña Grande”) is an Exploration Stage Property located in Brooks and Jim Hogg Counties, Texas and is on land located adjacent to, and to the south, north, and west of the Alta Mesa Uranium Project. The Company owns a 100% interest in the Mesteña Grande project. The property covers an approximate area of 35
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miles in a north-south direction by 30 miles in an east-west direction. For a more detailed discussion of the Mesteña Grande Uranium Project see the section titled “Material Properties,” below for this project.
Dewey Burdock Project, South Dakota
The Dewey Burdock Project is an Exploration Stage Property located in southwest South Dakota and is part of the northwestern extension of the Edgemont Uranium Mining District. The Company owns 100% interest in the Dewey Burdock Project. The project includes federal claims, private mineral rights and private surface rights controlling the entire area within the licensed project permit boundary as well as surrounding areas. The Company currently controls approximately 16,962 acres of net mineral rights and 12,613 acres of surface rights. For a more detailed discussion of the Dewey Burdock Project see the section titled “Material Properties,” below for this project.
Gas Hills Project, Wyoming
The Gas Hills Project is an Exploration Stage Property located in Wyoming. The Company owns a 100% interest in the Gas Hills Exploration Project located in the historic Gas Hills Uranium District 45 miles east of Riverton, Wyoming. The Gas Hills Project consists of approximately 1,280 surface acres and 12,960 net mineral acres of unpatented lode claims, a State of Wyoming mineral lease, and private mineral leases, within a brownfield site which has experienced extensive development including extraction and mill site production. For a more detailed discussion of the Gas Hills Project see the section titled “Material Properties,” below for this project.
Summary of Mineral Resources
The following table shows the Company’s estimate of Mineral Resources as defined in S-K 1300 through December 31, 2025.

Project | Measured Mineral Resources | Indicated Mineral Resources | Measured + Indicated | Inferred Mineral Resources
| Tons (000s) | Grade (% eU3O8) | Pounds (000s eU3O8) | Tons (000s) | Grade (% eU3O8) | Pounds (000s eU3O8) | Tons (000s) | Grade (% eU3O8) | Pounds (000s eU3O8) | Tons (000s) | Grade (% eU3O8) | Pounds (000s eU3O8)
ISR Properties |  |  |  |  |  |  |  |  |  |  |  |
Region: Texas |  |  |  |  |  |  |  |  |  |  |  |
South Texas Integrated ISR Uranium Project (Project Totals) | n/a | n/a | 2,754 | n/a | n/a | 773 | n/a | n/a | 3,527 | n/a | n/a | 308
Alta Mesa Project | 263.7 |  | 0.1 |  | 691.4 |  | 630.0 |  | 0.2 |  | 1,894.5 |  | 630.0 |  | 0.1 |  | 2,585.9 |  | 2,223.4 |  | 0.1 |  | 5,200.5 |
Mesteña Grande Project | - |  | - |  | - |  | - |  | - |  | - |  | - |  | - |  | - |  | 5,853 |  | 0.119 | 13,888 |
Region: South Dakota |  |  |  |  |  |  |  |  |  |  |  |
Dewey Burdock Project | 5,419.8 | 0.132 | 14,286.0 | 1,968.4 | 0.07 | 2,836.2 | 7,388.2 | 0.12 | 17,122.1 | 645.5 | 0.06 | 712.6
Region: Wyoming |  |  |  |  |  |  |  |  |  |  |  |
Gas Hill Project | 994.0 | 0.10 | 2,051.0 | 2,835.0 | 0.10 | 5,654.0 | 3,829.0 | 0.10 | 7,705.0 | 409.0 | 0.05 | 428.0
Total Mineral Resources | 6,677.5 |  | 0.33 |  | 19,782.4 | 5,433.4 |  | 0.37 |  | 11,157.7 | 11,847.2 | 0.32 | 30,940.0 | 9,130.9 |  | 0.33 |  | 20,537.10

Notes:
1.The Mineral Resource estimates in this table comply with the requirements of S-K 1300.
2.Mineral Resources were estimated using the following prices: (a) the South Texas Integrated ISR Project used a variable U 3 O 8 sales price ranging from $78.37/lbs up to $92.04/lbs with an overall average U 3 O 8 sales price of $87.05/lb (b) Alta Mesa Project used U 3 O 8 sales price that ranges from $82.00 to $89.00, with an average life of mine sales price of $83.43, (c) the Dewey Burdock Project used U 3 O 8 sales price ranging from $82.00 to $89.00, with an average sales price of $86.34 .and (d) Gas Hills Project used a U 3 O 8 sales price of $87.00/lb.
3.Mineral Resources were estimated using various %eU 3 O 8 or G.T. cut-off grades. The following are the averages for Measured and Indicated Resources: (a) the South Texas Integrated ISR Project used 0.2 to 0.3 GT cutoff with avg GT values ranging between 0.40 and 2.15, (b) the Alta Mesa Project used 0.145 %U 3 O 8, (c) the Mesteña Grande Project had no Measured or Indicated resources, (d) the Dewey Burdock Project used 0.12 % U 3 O 8 (0.66 avg. GT) and (e) the Gas Hills Project used 0.10 % U 3 O 8 (0.502 avg. GT).
4.The South Texas Integrated ISR Project includes Mineral Resources from the Upper Spring Creek Brevard, Upper Spring Creek – Brown and Rosita South – Cadena project areas.
Mining Properties and Technical Information
Management has evaluated whether any material changes have occurred since the filing of the last S-K 1300 technical report summaries filed for each of the material properties. Based on this evaluation, management has determined there have been no material changes to the scientific and technical information, including mineral resource and mineral reserve estimates, key assumptions, mining methods, processing parameters, capital or operating cost estimates, or material risks associated with our mineral properties. As a result, an updated S-K 1300 technical report summary has not been prepared
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for each of the material properties, and the previously filed technical report summaries are incorporated herein by reference.
Material Properties
South Texas Integrated ISR Project (Rosita CPP)
The South Texas Integrated ISR Project and associated well fields (collectively, the “STX Integrated Project”) are comprised of the Rosita CPP located in Duval County on a 200-acre tract owned by the Company, and multiple associated Satellite IX facilities at various project sites across south Texas. The STX Integrated Project is located within the South Texas uranium province, about 22 miles west of the town of Alice. The Rosita CPP was constructed in 1990 and was originally designed and constructed to operate as an up-flow extraction facility. The Rosita property holdings consist of mineral leases from private landowners covering approximately 3,475 gross and net acres of mineral rights.
The STX Integrated Project, including the Rosita CPP, was the starting point for the Company’s Texas production strategy. The Company commenced uranium extraction operations in 2023, at Rosita from the Rosita Extension wellfield (“Rosita Extension”), PAA-5. The Rosita CPP has an 800,000-pound U 3 O 8 per year production capacity and produced 5,728 pounds of U 3 O 8 for the year ended December 31, 2025 and 73,488 pounds U 3 O 8 in the year ended December 31, 2024, which was extracted and packaged. Cumulative dried pounds from PAA5 totaled 76,909 through December 31, 2025.
The following technical and scientific description of the STX Integrated Project is based in part on the South Texas Technical Report Summary. The report is filed Exhibit 96.1 to this Annual Report as of December 31, 2025. The South Texas Technical Report Summary was prepared in accordance with S-K 1300. The STX Integrated does not have “Mineral Reserves” and is therefore considered under SEC S-K 1300 definitions to be an Exploration Stage Property.
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Property and Operational Overview
Property Location
The Rosita CPP is located in Duval County, Texas, approximately 13.7 miles east of Freer and approximately 60 miles west of Corpus Christi at latitude 27.830423 and longitude -98.403543. This facility represents the central location of the STX Integrated Project and includes the CPP where resin from each satellite facility is processed. The Rosita CPP is supplied with uranium-loaded ion exchange resin from ISR mining at one or more of the project areas. Uranium Resources, Inc. initiated extraction at the Rosita CPP in 1990 and extracted 2.65 million pounds of U 3 O 8 from 1990 to 1999. The Company restarted the Rosita CPP facility in 2023. This plant was originally constructed as an IX facility in 1990, and its conversion to a CPP was completed in 2023. At the Rosita CPP, resin is processed, and uranium is recovered, precipitated as a slurry, and is then dried and packaged.
The Butler Ranch project consists of approximately 743 acres located in a rural area of Karnes County, Texas, approximately 44 miles south of San Antonio at latitude 28.887336 and longitude -98.059851. Butler Ranch is comprised of four different non-connected property leases over approximately 10 square miles in the western part of the county.
Upper Spring Creek - Brevard is located 6 miles northeast of the Ray Point Mining District in the Gulf Coast Uranium Province and South Texas Uranium Province or “GCUP”/“STUP” and is situated in Bee and Live Oak counties in Texas approximately halfway between San Antonio and Corpus Christi at latitude 28.567478 and longitude -98.024910. Three properties form the Brevard project area (Benham, Brevard, and Johnston) and total approximately 1,110 acres.
Upper Spring Creek – Brown Area project is located approximately 6 miles south-southwest of George West, Texas at the intersection of FM 889 and County Road 135 in Live Oak County at latitude 28.287159 and longitude -98.211350. The project includes two properties totaling approximately 87.88 acres. The properties (P1 and P2) are located east of FM 889 and northeast County Road 135. Brown includes three properties totaling approximately 247 acres. URI, Inc., a wholly owned subsidiary of the Company, owns both surface and mineral rights of P1 and owns surface and leases mineral rights for P2 at this project location. In 2025, a portion of the adjacent Houdman property was acquired which will be added to the project once permitting and drilling is completed in the area.
Rosita South-Caden a is located in Duval County, Texas, approximately 11.5 miles east of Freer and approximately 64 miles west of Corpus Christi at latitude 27.807052 and longitude -98.453480.
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Ownership
The STX Integrated Project is owned and operated by the Company. The Company has executed surface use and access agreements and fee mineral leases with surface and mineral owners at the STX Integrated Project. The net mineral ownership, royalty burden, and estimated annual costs are provided below for each of the projects:

Project | Gross Holdings Surface and/or Mineral (acres) | Net Mineral (acres) | Mineral Royalty Range | Estimated Annual Holding Costs
Rosita | 1,772 | 1,118 | 6.25% to 11.25% sliding scale based on Sales Price | $72,277
Butler Ranch | 675 | 509 | 6% to 12% sliding scale based on Sales Price | $9,344
Upper Spring Creek – Brevard | 280 | 280 | 6% to 12% sliding scale based on Sales Price | $14,000
Upper Spring Creek Brown Area | 728 | 449 | 5% to 12% sliding scale based on Sales Price | $7,275
Rosita South - Cadena | 3,619 | 2,439 | 5% to 12% sliding scaled based on Sales Price | $49,572

Infrastructure
Equipment, supplies and personnel needed for exploration and day-to-day operation are available from population centers such as San Antonio, and Corpus Christi. Specialized equipment for the wellfields is often available in Texas but may need to be acquired from outside of the state. The local economy for all project areas is geared toward oil and gas exploration, energy production, and ranching operations, providing a well-trained and capable pool of workers for ISR production and processing operations. Workers reside locally and commute to work daily. As a result of energy development since the early 1900s, all the project areas have existing or nearby electrical power, gas and adequate telephone and internet connectivity. Generally, the local and regional infrastructure is in place for all project areas including roads, power and maintenance facilities. Locally, exceptions include local access roads, wellfield development, local power and well control facilities that must be constructed.
Rosita CPP - Projects
The Company currently owns and operates the Rosita CPP within the Rosita Project radioactive materials license and injection permit boundaries. Site infrastructure includes the Rosita CPP and associated infrastructure, refurbishment of which was completed in 2023, electric transmission lines, water supply, ponds, and several paved and well-graded county roads that traverse the area providing access to the property. The remaining unused lands are primarily undeveloped farmland.
Butler Ranch
The Company leases the surface and mineral rights at Butler Ranch and has access to the land for exploration and development. Site infrastructure consists of residential buildings, undeveloped farmland, and retention ponds. Several paved and well-graded county roads traverse the area providing access to each property. Several electric transmission lines run adjacent to these roads and by the individual properties. Non-potable water will be supplied by water wells at or near the site. There is an existing water supply well at the site, but additional wells may need to be developed. Water extracted as part of ISR operations will be recycled for re-injection.
Upper Spring Creek - Brevard
The Company has or will obtain legal access to the land surface through confidential agreements. Site infrastructure consists of land to support cattle ranching and agriculture. Several paved county roads provide access to Brevard. An overhead electric transmission line and underground phone line run parallel to CR 140. Non-potable water will be supplied by wells at or near the site. There are two existing wells at Brevard, but additional wells may need to be developed. El Oso
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Water Supply Corporation, a public water system, also serves the area. Water extracted as part of ISR operations will be recycled for re-injection.
Upper Spring Creek – Brown
The Company owns both surface and mineral rights at the Brown and Geffert properties. The Company leases minerals located beneath the Geibel property and has access to the land for exploration and development. Site infrastructure consists of residential buildings, undeveloped farmland, and retention ponds. Several paved and well-graded county roads traverse the area providing access to each property. Several electric transmission lines run adjacent to these roads and by the individual properties. Non-potable water will be supplied by wells at or near the site. There is an existing water supply well at Upper Spring Creek- Brown, but additional wells may need to be developed. Water extracted as part of ISR operations will be recycled for re-injection.
Rosita South - Cadena
The Company has obtained legal access to the land surface through confidential agreements. Site infrastructure consists of residential buildings and land to support ranching and agriculture. Several paved and well-graded county roads traverse the area providing access to the property. Several electric transmission lines run adjacent to these roads to supply power to residential areas. No water supply sources have been developed for this site.
Economic Analysis
The South Texas Technical Report Summary contains an Initial Assessment which indicates a pre-tax Net Present Value of $104.3 million at an 8% discount rate compared to an after- tax Net Present Value of $81.8 million at an 8% discount rate.
The South Texas Technical Report Summary contemplates an annual production of just over 0.5 million pounds in the first year and then ramping up to approximately 0.8 million pounds by the second year. Total life of the project is estimated at approximately 9 years (6 years production followed by 3 years of restoration/surface reclamation). The NPV assumes cash flows take place in the middle of the periods and is calculated based on a discounted cash flow. The production estimates, Capital Expenses, and Operating Expenses, cost distributions used to develop the cash flow are based on the production and restoration models developed by the Company and incorporated in the cash flow. The cash flow assumes no escalation, no debt, interest, or capital repayment. The initial capitalized STX Integrated project construction was completed prior to this analysis. Excluding sunk costs which occurred prior to the operations proposed in the analysis, the STX Integrated is estimated to generate net cash flow over its life, before income tax, of $123.96 million and $97.01 million after income tax.
The mine plan and economic analysis are based on the following assumptions:
•NI 43-101 and S-K 1300 compliant estimate of Mineral Resources and a recovery factor of 80%,
•A variable U 3 O 8 sales price ranging from $78.37/lb up to $92.04/lb with an overall average U 3 O 8 sales price of $87.05/lb,
•A mine life 9 years (6 years production followed by 3 years of restoration/surface reclamation),
•A pre-income tax cost including royalties, state and local taxes, operating costs, and capital costs of $43.12/lb, and costs for the Project are based on actual costs from enCore’s currently operating south Texas ISR projects, economic analyses for similar ISR uranium projects, and WWC’s in house experience with mining and construction costs. All costs are in U.S. dollars.
The above information is based on Measured and Indicated Mineral Resources which do not have demonstrated economic viability. Given the speculative nature of mineral resources, there is no guarantee that any or all of the mineral resources included in the Initial Assessment will be recovered. The Initial Assessment is preliminary in nature and there is no certainty that the Project will be realized.
Geology, Mineralization and Deposit
The STX Integrated Project is located along the South Texas coastal plain, within the STUP. The uranium-bearing deposits in the STUP include sandstones in Tertiary formations ranging in age from Eocene (oldest) to Lower Pliocene (youngest). These permeable deposits are interbedded with claystones, mudstones and siltstones.
Uranium mineralization at the STX Integrated Project is typical of Texas roll-front sandstone deposits. The formation of roll-front deposits is largely a groundwater process that occurs when uranium-rich, oxygenated groundwater interacts with
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a reducing environment in the subsurface and precipitates uranium. The most favorable host rocks for roll-fronts are permeable sandstones with large aquifer systems. Interbedded mudstone, claystone and siltstone are often present and aid in the formation process by focusing groundwater flux. The roll-front deposits at Brevard are slightly different from the other roll-front deposits at Butler Ranch, Brown, and Cadena.
Permitting and Licensing
ISR projects in Texas require a number of permitting steps before recovery of uranium can commence. The first requirement is an exploration permit regulated by the Texas Railroad Commission. All sites have active exploration permits that allow drilling of exploration holes allowing enCore to collect data to determine if an economic ore body exists. The results of the drilling programs through exploration permits are used to define the resources on the associated property.
An aquifer exemption is determined by the U.S. Environment Protection Agency (“EPA”) that the aquifer or potion of the aquifer is mineralized and can not be used now or in the future as a source for drinking water. Once acknowledgment is made by the EPA that naturally occurring uranium exists in the aquifer in the designated area with that section of the aquifer specified as suitable for use as a drinking water source. Once it has been decided to move towards production, an aquifer exemption must be obtained through the EPA.
Texas is a Nuclear Regulatory Commission (“NRC”) agreement state with regulatory control over radioactive materials licensing for uranium recovery via a Radioactive Materials License (“RML”) and also has primary regulatory authority from the EPA over the permitting of Underground Injection Control “UIC” activities. An area UIC permit is required to progress to the next stage. This stipulates the area in which production can be pursued and the requirements regarding operations and reclamation of uranium ISR activities. Within the permitted areas, one or more PAAs must be obtained. To obtain a PAA, monitor wells must be installed and pump tests conducted to verify connectivity within the aquifer. Baseline wells must also be installed and analyses run to establish baseline testing and bonding must be put into place prior to operations. In order to extract and process natural uranium, a RML is needed. A RML requires part and parcel with the UIC permit and the application for the two are submitted simultaneously or as close together as possible. This stipulates the environmental and occupational monitoring that the licensee must carry out.
Current Permits for the STX Integrated Projects are as follows:

Upper Spring Creek - Brown |  |
Permit Type | Permit Number | Approved date | Current Status
Aquifer Exemption | EPA exemption ID: 6-114 – Boots/Brown | Jan. 1, 1982 | Approved
Area Permit | URO3095 | August 2, 2024 | Approved
Area Permit | Application for Upper Spring Creek - Brown Expansion Area Permit |  | Scheduled for 1H 2026
PAAs | Application submitted May 23, 2025 |  | Under review with the TCEQ
PAAs | Application to add PAA for the Upper Spring Creek Brown Expansion Project |  | Scheduled for 2H 2026
WDW | WDW467 |  | Pending approval - projected mid-April 2026
RML License | RO3653 | Issued May 22, 2025 | Approved

Upper Spring Creek – Brevard |
Permit Type | Permit Number | Approved date | Current Status
Aquifer Exemption | EPA exemption ID: 6-84 – Brevard | Jan. 1, 1982 | Approved

Rosita South – Cadena |  |  |
Permit Type | Permit Number | Approved date | Current Status

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Aquifer Exemption | EPA ID: 6-75 – Rosita Extension | Jul. 1, 1998 | Approved
Area Permit | Renewal application submitted Apr. 8, 2024. URO2880 | Nov. 15, 2007. Has subsequently been renewed Oct. 10, 2014. | Approved.
PAAs | N/A |  | PAA to be submitted once drilling identifies an orebody
WDW | WDW250 |  | Active: Wastewater will be piped to existing Class I Injection Wells No. 250.

Mineral Extraction Activities
The following table shows the extraction history from January 1, 2024 to December 31, 2025, from the STX Integrated:

Project | 2025 | 2024
South Texas Integrated ISR Project (dried and packaged) |  |
Pounds U3O8 | 5,728 | 73,488

Mineral resources that are not mineral reserves have not demonstrated economic viability and do not meet the requirement for all the relevant modifying factors. Stated mineral resources are derived from estimated quantities of mineralized material recoverable by ISR methods.
Mineral Resources
The Company mines uranium using the ISR recovery method. ISR has historically been utilized at the STX Integrated Project and is environmentally benign when compared to conventional open pit or underground recovery techniques. The STX Integrated Project Mineral Resources have a reasonable prospect for economic extraction due to the depth of mineralization, Grade x Thickness (“GT”) values, and continuity of mineralization. Studies completed to date support the conclusion that the STX Integrated Project deposits could be mined through ISR. The Mineral Resource estimates presented in the South Texas Technical Report Summary use cutoffs that are appropriate for ISR mining and may not be applicable to other mining methods.
Mineral reportable as Mineral Resources meets the following cutoff criteria:
•Minimum Grade: 0.020 %U 3 O 8
Grade is calculated at 0.5 ft depth increments, and values below this cutoff are excluded from reported resources.
•Minimum GT:
• 0.30 for Brevard, Cadena, and the measured resources at Brown
• 0.20 for the indicated and inferred resources at Brown
No specific minimum thickness is applied; however, the grade is calculated at 0.5 ft depth increments, making this the minimum possible thickness. The South Texas Technical Report Summary concludes the cutoffs used are typical of the ISR industry standard practice and are appropriate for current ISR methods.
The following key assumptions are used for all resource estimates:
• Resources are in permeable and porous sandstones; and
• Resources are located below the water table.
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Summary of Uranium Mineral Resources at the South Texas Integrated ISR Project through December 31, 2025.
(Based on a U 3 O 8 price of $87.05/lb.)

Project Area | GT Cutoff | Average GT | U3O8 (lbs)
Upper Spring Creek – Brevard Area
Measured | 0.30 | 0.59 | 800,000 |
Indicated | 0.30 | 0.40 | 38,000 |
Total Measured and Indicated |  |  | 838,000 |
Upper Spring Creek – Brown Area |  |
Measured | 0.30 | 1.17 | 1,339,000 |
Indicated | 0.20 | 2.15 | 720,000 |
Total Measured and Indicated |  |  | 2,059,000 |
Total Inferred | 0.20 | 1.36 | 308,000 |
Rosita South – Cadena |  |
Measured | 0.30 | 0.80 | 615,000 |
Indicated | 0.30 | 0.42 | 15,000 |
Total Measured and Indicated |  |  | 630,000 |

Notes:
1. Mineral resources as defined in S-K 1300.
2. All resources occur below the static water table.
3. The point of reference for mineral resources is in-situ at the STX Integrated Project.
4. Mineral resources are not mineral reserves and do not have demonstrated economic viability.
5. An 80% metallurgical recovery factor was considered for the purposes of the economic analysis.
6. There are no measured or indicated resources at Rosita CPP or Butler Ranch and no inferred resources at Rosita CPP, Butler Ranch, Brevard or Cadena.
There have been no changes to the STX Integrated Project Mineral Resources estimates for the year ended December 31, 2025, as compared to the year ended December 31, 2024.
Mine Design and Plans
A CPP and satellite facility collects and processes uranium. The CPP processing circuits consist of elution, precipitation, dewatering, drying and packaging. The satellite facility includes an IX and a resin transfer system to facilitate transfer of loaded resin by truck from the satellite to the CPP.
ISR has historically been utilized at the STX Integrated Project and is relatively environmentally benign when compared to conventional open pit or underground recovery techniques. This mining method utilizes injection wells to introduce a mining solution, called lixiviant, into the mineralized zone. To use ISR, the mineralized body must be saturated with groundwater, transmissive to water, and amenable to dissolution by the lixiviant. Previous operations have demonstrated uranium mineralization within the STX Integrated Project area is recoverable using the proposed ISR techniques.
In areas where the ore is not as widespread to allow for these patterns, encore will utilize an alternative line drive pattern placed over the recovery zone with wells alternating between production and injection wells. Pattern design is determined by the size and shape of the deposit, hydrogeological properties of the mining formation, and mining economics. enCore plans to use a combination of five-spot and alternating line drive patterns with recovery wells spaced 50-100 feet from injection wells.
Patterns are grouped into production units referred to as wellfields. Wellfields form a practical means for design, development and production, where groups of recovery wells and their associated injection wells are designed, constructed and operated, serving as the fundamental operating unit for distribution of the alkaline leach system, which is the process of mixing with alkaline carbonate solutions or other solutions to convert uranium into a soluble form.
An economic wellfield must cover the construction costs associated with well installation, connection of wells to piping that conveys the leach system between wellfields and the IX facility, wellfield and plant operating costs, and reclamation costs. To further facilitate planning, wellfields are grouped into PAs. PAs represent a collection of wellfields for which baseline data, monitoring requirements, and restoration criteria have been established for development of a Wellfield Hydrologic Data Package that will be submitted to regulatory authorities for mining approval.
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Wellfields will typically be developed based on conventional five-spot or alternating line drive patterns. Injection and recovery wells will be completed in a manner to isolate the screened uranium-bearing interval. To establish baseline data, monitoring requirements, and restoration criteria, monitor wells will be installed for each mine unit. Baseline production zone monitor wells will be completed in the deposit hosting sandstone unit to establish baseline water restoration criteria.
Production zone monitor wells will also be installed in a ring around the entire wellfield. This ring of perimeter monitor wells will be setback approximately 400 feet from the patterns and 400 feet apart, respectively. Certain exceptions can be made to this distance based upon land and ore outline limitations when approved in the permit. This monitor well ring will be used to ensure mining fluids are contained within the wellfield.
Overlying and underlying monitor wells will also be completed in hydro-stratigraphic units immediately above and below the production zone to monitor the potential for vertical lixiviant migration. Overlying monitor wells will be completed in all overlying units. Underlying wells will be completed in the immediately underlying unit.
Each injection and production well will be connected within a network of high-density polyethylene (HDPE) piping to an injection or production manifold located in the wellfield. The manifolds are connected to pipes that convey leaching solutions to and from the ion exchange columns in the CPP or Satellite facility. Flow meters, control valves, and pressure gauges in the individual well piping will monitor and control the individual well flow rates. Wellfield piping will be constructed using high-density polyethylene pipe.
The proposed uranium ISR process will involve the dissolution of the water-soluble uranium compound from the mineralized host sands at near neutral pH ranges. The lixiviant contains dissolved oxygen and carbon dioxide. The oxygen oxidizes the uranium, which is complexed with the bicarbonate formed by addition of carbon dioxide to the solution. The uranium-rich solution will be pumped from the recovery wells to the nearby CPP or satellite facility for uranium concentration with IX resin. A slightly greater volume of water will be recovered from the mineralized zone hydro-stratigraphic unit than injected, referred to as “bleed”, to create an inward flow gradient towards the wellfields. Thus, overall recovery flow rates will always be slightly greater than overall injection rates. This bleed solution will be disposed, as permitted, via injection into Class I Disposal Deep Wells.
Extraction Rates and Expected Mine Life
Extraction rate was calculated using an extraction model derived from wellfields operating in the South Texas region. The extraction model was applied to mineral resources based upon the observed monthly recovery with a recovery of 80% in 32 months. The figure below depicts the extraction forecast model for the wellfields for the STX Integrated Project.
Exploration Target
Conventional rotary drilling and down-hole geophysical logging were the primary exploration method at the STX Integrated Project. An exploration target has been identified at the Butler Ranch Project.
The ranges of potential quantity and grade of the exploration target are conceptual in nature. There has been insufficient exploration to define a mineral resource or mineral reserve at Butler Ranch. It is uncertain if further exploration will result
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in the target being delineated as a mineral resource and as such, the exploration target does not represent, and should not be construed to be, an estimate of a mineral resource or mineral reserve. Data evaluated to prepare the exploration target include project maps, mineral trend maps, historical ore body maps, cross sections, logs, previous technical reports, correspondence, and historical resource estimates and reporting. An extensive review of historical drill hole data was undertaken to estimate existing uranium resources within the property boundaries that have not been mined. Data from over 1,934 drill holes at Butler Ranch were evaluated.
This evaluation included the use of historical down-hole electric logs, drill hole location maps, a 2015 drilling project report, a data acquisitions summary, past memos and permits, and historical ore reserve estimates by Conoco in 1978 and 1981. In addition, log data was inventoried and includes summaries of mineralized drill hole intercepts with grade, thickness, and local survey coordinates for drill holes. Those projects without down-hole electric logs were evaluated for exploration potential. The ranges of potential quantity and grade of the exploration target are conceptual in nature. At the time of the of the technical report there has been insufficient exploration to define a mineral resource or mineral reserve. It is uncertain if further exploration will result in the target being delineated as a mineral resource.
An exploration target was estimated for several of the properties within the Butler Ranch Project area, as indicated in the table below. The estimates were derived from historical maps with mineral intercept data. No data can be confirmed by drill logs so resources cannot be classified. These properties are targets for further exploration in the future. The ranges of tonnage and grade of the exploration target could change as exploration activities are completed.

Rosita Butler Ranch – Exploration Target Estimate of U3O8 lbs |  |  |
Trend | Property | Host Strata | Acreage | Area (ft2) | Estimated Pounds at GT Cutoff | Estimated Pounds Turner Analog
1 | Moczygemba | Tordilla | 3.71 | 161,608 |  | 19,000 |  | 69,000 |
2 | Zunker | Tordilla | 14.08 | 613,325 |  | 72,000 |  | 264,000 |
3 | Garcia | Dubuse/Stone switch | 28.91 | 1,259,320 |  | 148,000 |  | 541,000 |
4 | Dziuk | Tordilla | 1.74 | 75,794 |  | 9,000 |  | 33,000 |
Totals |  |  |  | 2,110,047 |  | 248,000 |  | 907,000 |

Planned Work
The Company’s planned work will focus on commencing uranium extraction from Upper Spring Creek - Brown. The necessary initial steps included the completion of the regulatory approvals of the amendment to the RML RO3653, Class I UIC non-hazardous liquid byproduct disposal well and the PAA. Installation of the wellfield patterns, wellfield infrastructure, and the satellite IX facility for the site are currently ongoing. The first modules and the first half of the IX train will be ready to operate once the final PAA is received in 2026. The Company intends to conduct additional exploratory drilling on the Geffert and Houdman properties to identify additional Mineral Resources and increase confidence in the reported inferred Mineral Resources. In 2026, the Company intends to file applications to amend the RML RO3653 to incorporate Upper Spring Creek–Brown Expansion Project and file applications for Class III and Class I Underground Injection Control permits for Upper Spring Creek–Brown Expansion Project.
Alta Mesa Project (Alta Mesa CPP), Brooks County, TX
The Alta Mesa Project is a fully licensed and constructed CPP, located on over 203,000 acres of private land. Total operating capacity is currently approximately 1.5 million lbs. U 3 O 8 per year. Alta Mesa historically produced approximately 4.6 million lbs. of U 3 O 8 between 2005 and 2013, when full production was curtailed because of low uranium prices at the time by Mesteña Uranium LLC, the previous owner.
The following technical and scientific description of the Alta Mesa Project is based in part on the Alta Mesa Technical Report Summary. The report is filed as Exhibit 96.3 to this Annual Report on Form 10-K for the year ended December 31, 2025. The Alta Mesa Technical Report Summary was prepared in accordance with S-K 1300. The Alta Mesa Project does not have known “Mineral Reserves” and is therefore considered under SEC S-K 1300 definitions to be an Exploration Stage Property.
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Property and Operational Overview
Property Location
The Alta Mesa Project is an Exploration Stage ISR uranium mining project located in south Texas. The Alta Mesa Project lies within the southern part of the STUP. Uranium deposits in the STUP extend from Starr County at the international border with Mexico northeastward through Zapata, Jim Hogg, Brooks, Webb, Duval, Kleberg, McMullen, Live Oak, Bee, Atascosa, Karnes, Wilson, Goliad, and Gonzales counties. The Alta Mesa Project is located entirely within private land holdings of the Jones Ranch. The Jones Ranch is an approximately 380,000-acre ranch that was founded in 1897, and enCore controls over 200,000 of the 380,000 acres with mineral leases and options for uranium exploration and development.
The Alta Mesa Project is comprised of the Alta Mesa Mining Lease and the Alta Mesa CPP. The Alta Mesa Project consists of 4,597 acres. The active mine and CPP are located on the Alta Mesa project area approximately 35.5 miles southwest of Falfurrias via US Highway 281 to Ranch Road 755 to Ranch Road 430 to CR 314 to CR 315, Encino, Texas 78353, in Brooks County, Texas at approximately 26° 54’ 08” north longitude and 98° 18’ 54” west latitude.
Ownership
Mineral Rights
Royalty agreements have been established with mineral and surface owners. Furthermore, surface owners are paid an annual rental to hold the surface on behalf of enCore. Additionally, the agreements also provide for additional charges to the surface owner to cover surface damages and for reduction of husbandry grazing during field operations and other disturbances to the land.
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Mining Leases and Royalties
The Uranium Solution Mining Lease comprises Tract 5 and a portion of Tracts 1, 4, and 6 of “W.W. Jones Subdivision,” out of the “La Mesteña Y Gonzalena” Rafael Garcia Salinas Survey, Abstract N0. 480 and the “La Mesteñas” Ysidro Garcia Survey, Abstract No. 218, Brooks County, Texas. The Lease now covers uranium, thorium, vanadium, molybdenum, other fissionable minerals, and associated minerals and materials for the 4,597.67 acre property.
The lease, as amended, commenced on June 16, 2016, with a term of 15 years and the option for a 15-year extension, as long as the lessee is continuously engaged in any mining, development, production, processing, treating, restoration, or reclamation operations on the leased premises.
The lease includes provisions for royalty payments on net proceeds, less allowable deductions, received by the Company. The royalties range from 3.1% to 7.5% depending on the price received for the uranium. The lease also calls for a royalty on substances produced on adjacent lands but processed on the leased premises. The table below illustrates royalty details for the Alta Mesa Project.
Mining Lease Royalties

Royalty Holders | Number of Acres | Lessor Royalty | Primary Term
Mesteña Unproven Ltd. | 4,597.67 +/- | 7.5% Market value > $95.00/lb. U 3 O 8 | 15 years from amendment date with option for additional 15 years or as long uranium mining operations continue
Jones Unproven Ltd. | 4,597.67 +/- | 6.25% of Market Value > $65/lb. U 3 O 8 | 15 years from amendment date with option for additional 15 years or as long uranium mining operations continue
Mesteña Unproven Ltd. | 4,597.67 +/- | 3.15% of Market Value > $65/lb. U 3 O 8 | 15 years from amendment date with option for additional 15 years or as long uranium mining operations continue
Jones Unproven Ltd. | 4,597.67 +/- | 3.15% of Market Value > $65/lb. U 3 O 8 | 15 years from amendment date with option for additional 15 years or as long uranium mining operations continue

Permitting and Lease Option Agreement
The Amended and Restated Uranium Testing and Lease Option Agreement dated June 16, 2016 (the “Lease Option”), as part of the share purchase agreement between enCore Energy and the various holders of the Mesteña Project, covers all land containing mineral potential as identified through exploration efforts and covers uranium, thorium, vanadium, molybdenum, and all other fissionable materials, compounds, solutions, mixtures, and source materials. It covers 195,501 acres.
The initial term of the Lease Option was for eight years, which was extended for an additional seven years in April 2024 after payment of an extension fee. The Lease Option was further amended to extend the lease option period by an additional five years in June 2024.
Uranium Testing Permit and Lease Option Agreements Royalties

Royalty Holders | Number of Acres | Lessor Royalty | Primary Term
Mesteña Unproven Ltd. | 195.501 +/- | 7.5% Market value > $95.00/lb. U 3 O 8 | 8 years from amendment date with option for additional 7 years or as long uranium mining operations continue
Jones Unproven Ltd. | 195.501 +/- | 6.25% of Market Value > $65/lb. & </= $95/lb. U 3 O 8 | 8 years from amendment date with option for additional 7 years or as long uranium mining operations continue
Mesteña Unproven Ltd. | 195.501 +/- | 3.15% of Market Value > $65/lb. U 3 O 8 | 8 years from amendment date with option for additional 7 years or as long uranium mining operations continue
Jones Unproven Ltd. | 195.501 +/- | 3.15% of Market Value > $65/lb. U 3 O 8 | 8 years from amendment date with option for additional 7 years or as long uranium mining operations continue

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Surface Rights
The mineral leases and options described above include provisions for reasonable use of the land surface for the purposes of ISR mining and mineral processing. Alta Mesa is a fully licensed, operable facility with sufficient sources of power, water, and waste disposal facilities for operations and aquifer restoration. Alta Mesa LLC, either has in place or can obtain the necessary permits and/or agreements, and local resources are sufficient for current and future ISR operations within the Alta Mesa Project. The surface use agreements have been entered into with all the surface owners on the various prospect areas as part of the Membership Interest Purchase Agreement between Energy Fuels Inc. and the various holders of the Mesteña Project.
These agreements provide, amongst other things, for stipulated damages to be paid for certain activities related to the exploration and production of uranium. Specifically, the agreements call for U.S. Consumer Price Index (CPI) adjusted payments for the following disturbances: exploratory test holes, development test holes, monitor wells, new roads, and related surface disturbances. The lease also outlines an annual payment schedule for land taken out of agricultural use around the area of a deep disposal well, land otherwise taken out of agricultural use, and pipelines constructed outside of the production area.
Encumbrances
The Alta Mesa Project is encumbered by financial assurance instruments held by the state for completed wells, ISR mining and uranium processing to ensure reclamation and restoration of the affected lands and aquifers in accordance with state regulations and permit requirements.
Infrastructure
The Alta Mesa Project is well supported by nearby towns and services. Larger cities, Corpus Christi, McAllen and Laredo, are each about 100 miles or less from the site and are ready sources of materials and equipment. Major power lines are located across the Alta Mesa Project and are accessed for electrical service. The road system is comprehensive and well maintained and used for shipment of materials and equipment. Human resources are employed from nearby population centers.
The site has uranium drill holes and related infrastructure (e.g., small mud pits temporarily constructed to facilitate drill operations and water supply ponds), trucks and other equipment, historic and new wellfields, a CPP, administration building, shop and warehouse, environmental office, logging building and test pits. The Company renovated the CPP with equipment upgrades and refurbishments to the IX, elution and yellowcake processing circuits, which was completed in the second quarter of 2024.
The CPP has an automated control and monitoring system that allows remote monitoring of the facility and includes fail safe systems that can shut down portions of the system in the event of an upset condition. The facility is also fully secured with on-site and remote monitoring. Water supply for the Alta Mesa Project is from established and permitted local wells. Liquid waste from the processing facility is disposed via deep well injection through two permitted UIC Class I disposal wells. Solid waste is disposed of off-site at licensed disposal facilities. No tailings or other related waste disposal facilities are needed. Oil and gas-related infrastructure on the Alta Mesa Project includes oil and gas exploration and production wells, tank batteries, and numerous transmission and gathering pipelines.
Geology, Mineralization and Deposit
Uranium deposits are roll-fronts and are very similar to others found in the STUP. Deposit genesis is related to the presence of highly reduced groundwater systems generated from the biogenic decomposition of natural gas and/or hydrogen sulfide seepage derived from deeper formations through localized faulting. At Alta Mesa, uranium bearing groundwater moved from northwest to southeast within the Goliad Formation and encountered reduction zones associated with the Vicksburg fault system and the Alta Mesa salt dome and associated faulting which allowed the introduction of organics and other fluids upward through faults and fractures. The deposits are characterized by numerous vertically stacked roll-fronts controlled by stratigraphic heterogeneity, host lithology, permeability, reductant type and concentration, and groundwater geochemistry. Individual roll-fronts are a few tens of feet wide, 4 to 10 feet thick, and often thousands of feet long. Collectively, roll-fronts result in an overall deposit that is up to a few hundred feet wide, 50 to 75 feet thick and continuous for miles in length.
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History
From the early 1970s through 1999, the Alta Mesa Project mineral leases were held by various entities, including Chevron Minerals (which conducted initial drilling), Total Minerals, Cogema and URI, Inc. In 1999, the landowners of the land subject to the mineral leases formed Mesteña Uranium LLC, which completed most of the drilling in the Alta Mesa Project area and constructed the ISR facility in 2004, with production beginning in late 2005. Mesteña Uranium LLC operated the facility through February 2013, when the uranium market downturn occurred. Between 2005 and 2013, approximately 4.6 million lbs of uranium was extracted by ISR, with an average annual production of approximately 570,000 lbs yellow cake. In 2016, Energy Fuels, Inc. acquired both the Alta Mesa Project and the Mesteña Grande Project, and enCore acquired 100% of the interests of Alta Mesa and Mesteña Grande Project areas from a subsidiary of Energy Fuels, Inc. in November 2022. In February 2024, the Company and Boss entered into a joint venture for the Alta Mesa Project, whereby the Company holds a 70% interest and Boss holds 30%.
Permitting and Licensing
The most significant permits and licenses required to operate the Alta Mesa Project are (1) the Source and Byproduct Materials License, which was issued by TCEQ (formerly Texas Bureau of Radiation Control) in 2002; (2) the Class III Area Permit issued by TCEQ in April 2000; and (3) Production Area Authorizations issued at various times since April 2000, two deep Class I injection non-hazardous disposal wells issued by TCEQ in April 2000 and an aquifer exemption issued by USEPA in 2002, with the area expanded in a revised Aquifer Emption dated 2009. Similar permits would be required for the Mesteña Grande Project area depending upon the nature of operations and their integration with the Alta Mesa facility.
Preliminary investigations including exploration and environmental monitoring of the Alta Mesa expansion project were initiated in the Fall of 2025. Amendment applications for RML No. R05360 and the Class III Area Permit No. UR03060 have been started with projected submittals in the Fall of 2026. Amendment to add the Production Area Authorization will be submitted during 2026.
PAA-1 has been extracted, and the groundwater restoration has been approved by the TCEQ. PAA-2 through PAA-6 is either in standby or in the process of groundwater restoration. PAA-7 is currently being extracted.
The status of the various federal and state permits and licenses are summarized in the table below:
Permitting Status

Permit/License | Status
FCC - Radio License FRN0020106654 | Active
Sewage System OSSF | Active
PAA-1 | Active
PAA-2 | Active
PAA-3 | Active
PAA-4 | Active
PAA-5 | Active
PAA-6 | Active
PAA-7 | Active
Uranium Exploration Permit 125 | Active
Radioactive Material License - R05360 | Timely Renewal
L05939 - Sealed Source RML for PFN | Active
TCEQ Aquifer Exemption | Active
EPA Aquifer Exemption | Active
UIC Class III Mine Area Permit UR03060 | Timely Renewal
USCOE 404 exemption SWG-1998-02466 | Active
UIC Class I disposal well permit WDW-365 | Active
UIC Class I disposal well permit WDW-366 | Active

Mineral Resources and Extraction Activities
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Mineral Resources
The following table shows the extraction history from the beginning of extraction activities as of December 31, 2025 and December 31, 2024, from the Alta Mesa ISR Project:

Project | 2025 | 2024 |  |  |  |  |  |  |  |  |
Alta Mesa ISR Project |  |  |  |  |  |  |  |  |  |  |
Pounds U 3 O 8 | 699,000 | 190,000 |  |  |  |  |  |  |  |  |

Mineral resources that are not mineral reserves have no demonstrated economic viability and do not meet the requirement for all the relevant modifying factors. Stated mineral resources are derived from estimated quantities of mineralized material recoverable by ISR methods.
Key Assumptions, Parameters and Methods for Mineral Resource Estimates
Key Assumptions
•Mineral resources have been estimated based on the use of the ISR extraction method and yellowcake production, and based on data collected from historical drill holes;
•Average density of 17.0 cubic feet per ton was used based on historical sample measurements;
•Price forecast, production costs and an 80% metallurgical recovery were used to estimate mineral resources;
•Average wellfield recovery of 80% that accounts for dilution from mining hydro-logic efficiency and metallurgical recovery;
•Average plant recovery of 98%; and,
•Average uranium price of $83.43 based on TradeTech’s Uranium Market Study 2023: Issue 4.
Measured Mineral Resources
Drilling is denser than 50 x 200 feet spacing for mineralized zones characterized by a uniform and easily correlatable roll-front morphology, from one drilling fence line to another. Mineralization must be continuous between drill fences. The hydrogeological properties of the hosting horizon are studied by aquifer pump tests. The amenability of mineralization to ISR mining is demonstrated by laboratory leach tests. Mineralization is characterized by sufficient confidence in geological interpretation to support detailed wellfield planning and development with no or very little changes expected from additional drilling.
Indicated Mineral Resources
Drilling density equivalent to or denser than 50 x 200 feet spacing for mineralized zones characterized by a uniform and easily correlatable roll-front morphology, from one drilling fence line to another. Mineralization must be continuous between drill fences. The hydrogeological properties of the hosting horizon are studied by aquifer pump tests. The amenability of mineralization to ISR mining is demonstrated by laboratory leach tests. Mineralization is characterized by sufficient confidence in geological interpretation to support wellfield planning and development with some changes expected from additional drilling.
Inferred Mineral Resources
Drilling density equivalent to about 800 feet spacing for mineralized zones characterized by less uniformity and not easily correlatable roll-front morphology, from one drilling fence line to another. Mineralization must be continuous between drill fences but there is less confidence in geologic interpretation. The hydrogeological properties of the hosting horizon are studied by aquifer pump tests. The amenability of mineralization to ISR mining is demonstrated by laboratory leach tests. Mineralization is characterized by insufficient confidence in geological interpretation to support wellfield planning and development due to significant changes expected from additional drilling.
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Mineral Resource Estimates
A summary of the Project’s mineral resource estimates is provided in the table below.
Summary of Uranium Mineral Resources at the Alta Mesa ISR Project as of December 31, 2025.
(Based on a metal price of $83.43/lb. U 3 O 8)

Category | Tons (x 1,000) | Avg Grade (%) U 3 O 8 | Total Lbs (x 1000) U 3 O 8
Measured | 263.7 | 0.136 | 691.4
Indicated | 630.0 | 0.150 | 1,894.5
Total Measured and Indicated | 894.0 | 0.145 | 2,585.9
Inferred | 2,223.4 | 0.112 | 5,200.5
Total Inferred | 2,223.4 | 0.112 | 5,200.5

Notes:
1 enCore reports mineral reserves and mineral resources separately. Reported mineral resources do not include mineral reserves.
2 The geological model used is based on geological interpretations on section and plan derived from surface drill hole information.
3 Mineral resources have been estimated using a minimum grade-thickness cut-off of 0.30 ft% U 3 O 8.
4 Mineral resources are estimated based on the use of ISR for mineral extraction.
5 Inferred mineral resources are estimated with a level of sampling sufficient to determine geological continuity but less confidence in grade and geological interpretation such that inferred resources cannot be converted to mineral reserves.
There have been no changes to the Alta Mesa Project Mineral Resource estimates for the year ended December 31, 2025, as compared to the year ended December 31, 2024.
Mining, Processing and Recovery Methods
Mining Method
The Company is mining uranium using ISR. An alkaline leach system of carbon dioxide and oxygen is used as the extracting solution. Bicarbonate, resulting from the addition of carbon dioxide to the extracting solution, is the complexing agent. Oxygen is added to oxidize the uranium to a soluble +6 valence state.
Mine Designs and Plans
From March 2023 to June of 2024, the Company renovated the CPP with equipment upgrades and refurbishments to the IX, elution and yellowcake processing circuits. During this timeframe, the Company also advanced mine development. Production and injection wells are installed to facilitate the in-situ mining process. Injection wells are used to inject chemically fortified natural groundwater into the ore body liberating uranium. Production wells are used to recover the uranium rich waters by pumping the production fluid to the surface. Wells are completed in only one mineralized zone at a time and in a manner that focuses fluid flow across the deposit. The Alta Mesa Project includes fully permitted production areas, including PAA-6 and PAA-7, with brownfield drilling being conducted in PAA-8 and PAA-9. As of December 31, 2024, in PAA-7, 943 holes were drilled of which 224 were deemed suitable for further development into injection and production wells. In PAAs 8 through 10, 161 holes were drilled targeting mineralization in multiple horizons. As of December 31, 2025, in PAA-7, 1,036 holes were drilled, of which 212 were deemed suitable for further development into injection and production wells. In PAA-3 extension, PAA-8 through PAA-10, a total of 526 holes were drilled, of which 10 were deemed suitable for further development into injection and production wells. Drilling targeted mineralization in multiple horizons.
Production Rates and Expected Mine Life
Flow rate and head grades will be maintained to achieve annual production rate. New wellfields will be developed and commissioned at a rate to ensure adequate head grades are maintained as operating wellfields are depleted to achieve production objectives.
Production rate was calculated using a production model as shown below. The production model was applied to mineral resources using the following parameters:
•Average recovery well flow rate of 45 gpm
•Maximum CPP flow rate of 7,500 gpm
•Average feed grade of 60 ppm U 3 O 8
•80% mineral recovery in 32 months
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Production forecast by year are illistrated below. Alta Mesa Project’s wellfield solution head grades peaked at approximately 140 mg/L U 3 O 8 and averaged approximately 65 mg/L U 3 O 8 for both 2024 and 2025.
Production Forecast Model
Mine Construction
In February 2023, the Company completed the acquisition of the Alta Mesa Project from Energy Fuels Inc., establishing ownership of a second south Texas uranium processing plant. In March 2023, the Company announced its formal decision to resume commercial operations in early 2024 and commenced pre-construction and drilling activities preparing staging areas, drill pads and identification of equipment requiring maintenance or repair.
Processing and Recovery
The CPP collects and processes uranium. The CPP processing circuits consists of IX, elution, precipitation, dewatering, drying and packaging. Part of enCore’s operational plan is to mine uranium from satellite properties processing product at one of the company’s CPPs. The CPP has an IX uranium recovery capacity of 1.5 million lbs of uranium per year through three separate IX circuits.
In February 2024, enCore submitted the License R05360 Renewal and Amendment Application to the TCEQ requesting amendment to the existing license activities authorization to construct and operate remote ion exchange (RIX) facilities within the existing license area and to process resin for uranium extraction that is generated from other sources. RIX are self-contained stand-alone processing facilities with an IX circuit and a resin transfer system. RIX is the same uranium recovery process as IX in the CPP. Once uranium is recovered, loaded resin will be transferred via the resin transfer system and trucked to the CPP.
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Planned Work
•Complete installation of remaining modules in PAA-7.
•Continue uranium extraction in PAA-7.
•Install monitor wells for PAA-8.
•Install production wells and infrastructure for PAA-3 extension and begin production upon receipt of PAA.
•Continue to develop resources in the LC South area to define the next PAA.
•Continue exploration at the newly acquired Alta Mesa East property to develop a resource on the property
•There is ongoing wide spread drilling to determine a sitewide geologic understanding.
•Closer spaced drilling will continue to define total mineralization and define potential production area limits.
•Permitting efforts have begun on the Aquifer Exemption, RML and the UIC permit.
Mesteña Grande Uranium Project, Brooks and Jim Hogg Counties, Texas
The Mesteña Grande Project is an ISR uranium project located in south Texas. The Mesteña Grande Project lies within the southern part of the STUP. Uranium deposits in the STUP extend from Starr County at the international border with Mexico northeastward through Zapata, Jim Hogg, Brooks, Webb, Duval, Kleberg, McMullen, Live Oak, Bee, Atascosa, Karnes, Wilson, Goliad, and Gonzales counties. The center point of the Mesteña Grande Project is approximately 27.089° north longitude and 98.501° west latitude.
Part of the Company’s operational plan is to mine uranium from satellite properties processing IX resin at one of the Company’s CPPs. At the Alta Mesa Project, enCore has an active mine and CPP. Portions of the Project are located adjacent to the south and to the north of the Alta Mesa Project, with other parts located as much as 50 miles northwest of the CPP. enCore plans to develop and advance the Mesteña Grande Project and process uranium at Alta Mesa.
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The following technical and scientific description of the Mesteña Grande Project is based on the Mesteña Grande Technical Report Summary. Mesteña Grande does not have known “Mineral Reserves” and therefore is considered under SEC S-K 1300 definitions to be an Exploration Stage Property. The report is filed as Exhibit 96.5, to this Annual Report as of December 31, 2025. The South Texas Technical Report Summary was prepared in accordance with S-K 1300.
Property and Operational Overview
The Mesteña Grande Project properties include multiple project areas, including Mesteña Grande North (MGN), Mesteña Grande Central (MGC), Mesteña Grande South (MGS), Mesteña Grande Alta Vista (MGAV), Mesteña Grande El Sordo (MGES), Mesteña Grande North Alta Mesa (MGNAM) and the Mesteña Grande South Alta Mesa (MGSAM) project areas. The properties collectively total 194,119 acres. The northwest corner of the Mesteña Grande Project is adjacent to and extends for about 36 miles north-northwest of the Alta Mesa CPP from Brooks County into Jim Hogg County, Texas. The project extents cover approximately 30 miles in an east-west direction, and approximately 35 miles in a north-south direction.
Ownership
Mineral ownership in Texas is private estate. Under the Relinquishment Act of 1919, as subsequently amended, the surface owner is made the agent of the state for the leasing of such lands, and both the surface owner and the state receive a fractional interest in the proceeds of the leasing and production of minerals.
The Jones Ranch holdings include private surface and mineral rights for oil and gas and other minerals, including uranium. Uranium recovered at the Mesteña Grande Project will be processed at the Alta Mesa CPP under the current Uranium Solution Mining Lease, as described above under the property description for the Alta Mesa Project.
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Infrastructure
The site has uranium drill holes and related infrastructure (e.g., small mud pits temporarily constructed to facilitate drill operations and water supply ponds), and trucks and other equipment. Because of the Project’s proximity to Alta Mesa, Alta Mesa does serve as a base of operation for, administration, shop and warehouse, environmental support, and logging services. Water supply for the Mesteña Grande Project is from established and permitted local wells. Solid waste is disposed off-site at licensed disposal facilities. No tailings or other related waste disposal facilities are needed. Major power lines are located across the Mesteña Grande Project for grid access, with a comprehensive, well-maintained road system used for shipment of materials and equipment. Human resources are employed from nearby population centers, such as Corpus Christi, McAllen and Laredo, which are each about 100 miles or less from the site and are ready sources of materials and equipment.
Geology, Mineralization and Deposit
Uranium deposits are roll-fronts, typical to others found in the South Texas Uranium Province. Deposit genesis is related to the presence of highly reduced groundwater systems generated from the biogenic decomposition of natural gas and/or hydrogen sulfide seepage derived from deeper formations through localized faulting. At Mesteña Grande, uranium mineralization occurs in numerous locations within the Goliad, Oakville, and Catahoula Formations and is formed in much the same way as at Alta Mesa. Uranium bearing groundwater within each of these formations encountered reduction within the groundwater associated with major growth fault systems within the region.
The deposits at Mesteña Grande are characterized by vertically stacked roll-fronts controlled by stratigraphic heterogeneity, host lithology, permeability, reductant type and concentration, and groundwater geochemistry. Individual known roll-fronts may be few tens of feet wide, 2 to 10 feet thick, and often thousands of feet long. Collectively, roll-fronts are inferred to result in an overall deposit that is up to a few hundred feet wide, 50 to 75 feet thick and continuous for miles in length.
History
As discussed above regarding the Alta Mesa Project, Mesteña Uranium LLC completed most of the drilling on the adjacent Alta Mesa project and constructed the ISR facility and began production in the fourth quarter of 2005 until February 2013. Mesteña Uranium, LLC acquired the Mesteña Grande projects in 2006 as an exploration option to provide additional uranium feed to the Alta Mesa plant.
On June 17, 2016, Energy Fuels Inc., acquired both the Alta Mesa and the Mesteña Grande Projects. In November 2022, the Company entered into a Membership Interest Purchase Agreement dated November 14, 2022, with EFR White Canyon Corp., a subsidiary of Energy Fuels, to acquire four limited liability companies that together hold 100% of the Alta Mesa and Mesteña Grande Projects. Acquisition costs were $120 million payable in a combination of cash and vendor take-back convertible note secured against the assets.
In February 2024, the Company entered a joint venture with Boss. to develop and advance the Project. enCore retains ownership of 70% of the project and Boss holds 30%. See the discussion above under the description of the Alta Mesa Project for more information regarding the joint venture with Boss.
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Licensing and Permitting
The Project is not permitted or licensed to operate with the exception of the permits necessary for exploration. The most significant permits and licenses that will be required to operate the Project are (1) the TCEQ Source and Byproduct Materials License, (2) the Class I Mine Area Permit issued by TCEQ and (3) Production Area Authorizations (UIC Class III) that are issued at various times through LOM, deep injection non-hazardous Class I disposal wells issued by TCEQ, and an USEPA aquifer exemption.
The timing to prepare the applications and for agency review and approval is estimated to be 3 to 4 years and is not entirely in enCore’s control. The TCEQ’s ability to process enCore’s applications is dependent on the workload of the agency. With the renewed interest in uranium recovery, the application process timeline could be longer due to additional requests for ISR permits and licenses.
The costs to obtain these licenses and permits is estimated to be $2.87 million. These costs include environmental baseline sampling of the air, water (surface and subsurface), soils, and vegetation in the vicinity of the proposed activities. The background radionuclide concentrations in the environment will also be determined. For the UIC Class III permits monitor wells will be installed and sampled to establish baseline water quality prior to mining.
Mineral Resources
Key assumptions for the following Mineral Resource estimates are as follows:
•Mineral resources have been estimated based on the use of the ISR extraction method and yellowcake production as well as data collected from drillholes;
•Average density of 17.0 cubic feet per ton was used, based on historical sample measurements;
•Price forecast, production costs and an average wellfield recovery of 60% that accounts for dilution from mining hydrologic efficiency and metallurgical recovery, were used to estimate mineral resources,
•Average plant recovery of 98 %; and
•Average LOM uranium price of $85.48 based on TradeTech’s Uranium Market Study 2023: Issue 4.
Key Methods for the following Mineral Resources estimates are as follows:
• Geological interpretation of the orebody was done on section and plan from surface drill hole information,
• The orebody was modeled creating roll-front outlines for each of the deposit’s individual mineralized zones; and,
• Geological modeling and mining applications used ArcGIS Pro.
Measured Mineral Resources
Drilling is denser than 50x100 feet spacing for mineralized zones characterized by a uniform and easily correlatable roll-front morphology, from one drilling fence line to another. Mineralization must be continuous between drill fences. The hydrogeological properties of the hosting horizon are studied by aquifer pump tests. The amenability of mineralization to ISR mining is demonstrated by laboratory leach tests. Mineralization is characterized by sufficient confidence in geological interpretation to support detailed wellfield planning and development with no or very little changes expected from additional drilling.
Indicated Mineral Resources
Drilling density equivalent to or denser than 200x400 feet spacing for mineralized zones characterized by a uniform and easily correlatable roll-front morphology, from one drilling fence line to another. Mineralization must be continuous between drill fences. The hydrogeological properties of the hosting horizon are studied by aquifer pump tests. The amenability of mineralization to ISR mining is demonstrated by laboratory leach tests. Mineralization is characterized by sufficient confidence in geological interpretation to support wellfield planning and development with some changes expected from additional drilling.
Inferred Mineral Resources
Drilling density equivalent to about 800 feet spacing for mineralized zones characterized by less uniformity and not easily correlatable roll-front morphology, from one drilling fence line to another. Mineralization must be continuous between drill fences but there is less confidence in geologic interpretation. The hydrogeological properties of the hosting horizon are studied by aquifer pump tests. The amenability of mineralization to ISR mining is demonstrated by laboratory leach tests.
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Mineralization is characterized by insufficient confidence in geological interpretation to support wellfield planning and development due to significant changes expected from additional drilling.
Mineral Resource Estimates
Summary of Uranium Mineral Resources at the Mesteña Grande Uranium Project as of December 31, 2025.
Based on a metal price of $85.48/lb U 3 O 8

Category | Tons (x 1,000) | Avg Grade (%) U 3 O 8 | Total Lbs (x 1000) U 3 O 8
Measured | - |  | - |  | - |
Indicated | - |  | - |  | - |
Total Measured and Indicated | - |  | - |  | - |
Inferred | 5,852.8 |  | 0.1 |  | 13,887.9 |
Total Inferred | 5,852.8 |  | 0.1 |  | 13,887.9 |

Notes:
1.The Company reports mineral reserves and mineral resources separately. Reported mineral resources do not include mineral reserves.
2.The geological model used is based on geological interpretations on section and plan derived from surface drillhole information.
3.Mineral resources have been estimated using a minimum grade-thickness cut-off of 0.30 ft% U 3 O 8.
4.Mineral resources are estimated based on the use of ISR for mineral extraction.
5.Inferred mineral resources are estimated with a level of sampling sufficient to determine geological continuity but less confidence in grade and geological interpretation such that inferred resources cannot be converted to mineral reserves.
There have been no changes to the Alta Mesa Project Mineral Resources estimates for the year-ended December 31, 2025, as compared to the year ended December 31, 2024.
Mining, Processing and Recovery Methods
The Company plans to recover uranium using resin IX (“RIX”). RIX are self-contained stand-alone processing facilities with an IX circuit and a resin transfer system. The process flow of the RIX is the same as the IX circuit in the CPP. Once uranium is recovered at the RIX, the loaded resin will be transferred via the resin transfer system to a resin trailer and trucked to the CPP for elution, precipitation, drying, and packaging. The RIXs at the Mesteña Grande Project will be larger to accommodate an increased flow rate. Infrastructure at the Alta Mesa Project will allow for processing of all RIX resin at the Alta Mesa CPP. For a description of mining method, mine design and plans and processing at Alta Mesa, see the discussion above for the Alta Mesa Project.
Dewey Burdock Project, Fall River and Custer Counties, South Dakota
The Dewey Burdock Project is an Exploration Stage Property located in southwestern South Dakota and forms part of the northwestern extension of the Edgemont Uranium Mining District. The Dewey Burdock Project includes federal claims, private mineral rights and private surface rights controlling the entire area within the licensed project permit boundary as well as surrounding areas. The Company currently controls approximately 16,962 acres of net mineral rights and 12,613 acres of surface rights. The net result of the royalty and rental payments results in a cumulative 4.85% surface and mineral royalty.
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Property and Operational Overview
The Dewey Burdock Project is in southwestern South Dakota and forms part of the northwestern extension of the Edgemont Uranium Mining District. The project area is in Townships 6 and 7 South, Range 1 East, of the Black Hills Prime Meridian approximately 13 miles north-northwest of Edgemont. The county line dividing Custer and Fall River countries, South Dakota, lies at the confluence of Townships 6 and 7 South. The permitted area encompasses approximately 10,580 acres of mostly private land and 240 acres under the control of the Bureau of Land Management.
Ownership
Mineral titles are comprised of federal claims, private minerals and private surface rights within the permit boundary and surrounding areas. Access and mineral rights are currently held by a combination of private surface use agreements, access and mining lease agreements, purchase agreements and federal mineral claims. The Company currently holds 16,962 mineral acres with an annual cost of $401,307. These royalties for fee minerals range from 2% to 4% of gross sales. Leases have been acquired from various landowners with several levels of payments and obligations. Where the Company will develop mineral resources, both surface and minerals are leased or controlled by unpatented mineral claims. Furthermore, enCore controls all surface and mineral rights within the permit boundary. Most leases and purchase agreements are maintained through annual payments. Several leases are subject to an annual payment that is based on uranium spot price at payment due date. Claims are held by annual payments to the Bureau of Land Management.
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Infrastructure
The Dewey Burdock Project is well supported by nearby towns and services. Major power lines are located across the project for electrical service. The Burlington Northern Sante Fe railroad crosses the Dewey Burdock Project, and a major railroad siding occurs at Edgemont and may be used for shipment of materials and equipment, if necessary. Human resources will be employed from nearby population centers, such as Edgemont, Custer and Hot Springs. Mineral and surface area leases have flexibility for placement of tanks, out buildings, storage areas and pipelines. The project area has no mining facilities or buildings. The only site equipment related to mining includes a weather monitoring station, radiological monitoring stations and monitor wells. Estimated capital costs are $262.2 million, which includes pre-construction permitting and licensing, wellfield development, the CPP, satellite and associated infrastructure. Estimated capital costs are $264.2 million, which includes pre-construction permitting and licensing, wellfield development, the CPP, satellite and associated infrastructure.
Geology, Mineralization and Deposit
The Edgemont Uranium District is located on the southwest side of the Black Hills Uplift. The Black Hills Uplift is a Laramide Age structure forming a northwest trending dome about 125 miles long x 60 miles wide located in southwestern
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South Dakota and northeastern Wyoming. The uplift has deformed all rocks in age from Cambrian to latest Cretaceous. Subsequent erosion has exposed these rock units dipping outward in successive elliptical outcrops surrounding the central Precambrian granite core. Differential weathering has resulted in present day topography of concentric ellipsoids of valleys under softer rocks and ridges held up by more competent units. The Cretaceous sediments contain uranium roll front deposits in the more porous and permeable sands within the Inyan Kara Group, Lakota Formation and Fall River Formations. The entire Inyan Kara Group consists of basal fluvial sediments grading into near marine sandstones, silts and clays deposited along the ancestral Black Hills Uplift. The sandstones are continuous along the entire western flank of the uplift and dip about 3 degrees to the southwest in the Dewey Burdock Project area.
The Lakota and Fall River Formations were deposited by northward flowing stream systems. Sediments are characterized by point bar and traverse bar deposition in meandering fluvial systems. Sand units fine upward with numerous cut-and-fill structures indicative of channel migration depositing silt and clay upon older sand. The Fall River sands are noticeably thinner with marine sediments superimposed directly on the fluvial sands.
The depositional characteristics of the Lakota and Fall River Formations result in stratigraphic heterogeneity within the sands. Because of this heterogeneity, uranium mineralization occurs as multiple sinuous roll fronts, instead of one large front as is observed in more homogeneous sands. Individual roll fronts are continuous and generally trend along strike but may or may not overlap. Individual roll fronts average about 8 feet thick and 30 feet wide. Where overlapping occurs the deposit can be tens of feet thick and hundreds of feet wide. The strike length of individual roll fronts is variable but often on the order of thousands of feet, where the total strike length of the deposit is measured in miles. Depth to mineralization is variable and ranges from about 180 to 920 feet.
History
Uranium minerals were discovered in the vicinity of the Dewey Burdock Project as early as 1952 and were mined by small mining companies using open pit, adit or shallow underground mines. These mining companies leased the mineral rights from mineral or other claim owners and by the late 1950s the deposits came under the control of Susquehanna, which owned the process mill located in Edgemont. Susquehanna mined most of the known shallow uranium deposits prior to the mill’s closure in 1972.
During the uranium boom of the 1970s, several companies returned to the Dewey Burdock Project area, acquired leases and began exploration for deeper deposits. Multiple exploration companies, including Wyoming Mineral, Homestake Mining Company, Federal Resources and Susquehanna discovered deeper uranium roll-front type mineralization. The project area went through multiple subsequent owners, including the Tennessee Valley Authority (“TVA”), which developed a resource to warrant mine plans that included an underground mine shaft at both the Burdock and Dewey sites and a new uranium mill that was planned to be near Burdock. On October 29, 2014, Powertech merged with Azarga Resources Limited forming Azarga Uranium. To further consolidate project resources, Azarga entered into a binding property purchase agreement with Energy Metals on November 18, 2005, whereby Azarga acquired a 100% interest in 119 mineral claims covering approximately 2,300 acres. In 2021, Azarga and enCore entered into an agreement whereby enCore was to purchase Azarga. In September of 2021, the acquisition was finalized with enCore acquiring multiple assets in various stages of development including the advanced stage Dewey Burdock Project.
Licensing and Permitting
The Dewey Burdock Project is the first uranium ISR facility to submit permit applications in the state of South Dakota. As such, there is inherent risk in a new permitting process, regulatory unfamiliarity with ISR methods, and an untested review period. The amount of time required for regulatory review of all permits associated with the commissioning of an ISR facility is highly variable and directly affects project economics. The Company intends to have all permits necessary to construct in 2027. The timeframe to obtain licenses and permits is expected to be impacted by environmental nongovernmental organizations (“NGO’s”) and public contestation of both state and federal permits and licenses. Time for contested cases has been accounted for in the project development schedule.
The Dewey Burdock Project has drawn attention from environmental NGO’s, tribal governments, and individuals in the public. enCore is managing this risk through the state and federal permitting processes. Extensive efforts by the regulatory agencies have proceeded to near completion of all major permitting and licensing actions.
The NRC license (SUA 1600), which was issued in 2014, challenged and appealed, is now in good standing and in timely renewal. The license renewal application is being reviewed by the NRC with a licensing decision currently projected for May 2026. The NRC’s safety evaluation report was completed with favorable results in December 2025. The NRC’s
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National Historic Preservation Act (“NHPA”) and National Environmental Policy Act (“NEPA”) reviews are expected to conclude shortly before the licensing decision in May 2026. In January 2025, the NRC’s Atomic Safety and Licensing Board (“ASLB”) granted a petition by the Oglala Sioux Tribe (“OST”), Black Hills Clean Water Alliance, and NDN Collective (“Petitioners”) to challenge the license renewal application. enCore has appealed the ASLB’s decision to admit Petitioners as parties to the licensing proceeding, which appeal is currently pending before the NRC. The NRC license remains effective during the pendency of license renewal proceedings.
The EPA issued the Class III and Class V Area UIC permits and Aquifer Exemption in 2020. The OST challenged the Class III and Class V UIC permits at EPA’s Environmental Appeals Board (“EAB”) and the Aquifer Exemption in the Eighth Circuit Court of Appeals. The EAB remanded the Class III and Class V permits to the EPA to supplement the administrative record and the permits were subsequently reissued without change on March 14, 2025. The Petitioners subsequently challenged the reissued permits at the EAB. On September 16, 2025, the Company announced that the EAB denied in full the Petitioners’ challenge against the EPA’s issuance of Class III and Class V UIC permits. The decision upholds, finalizes, and activates all of the Dewey Burdock Project federal permits and allows commencement of state permitting activities in 2026, accelerating the Dewey Brock Project towards development ahead of schedule.
The EAB decisions regarding EPA compliance with NHPA and NEPA were favorable rulings and consistent with the 2023 D.C. Circuit Court of Appeals rulings where similar appeals were made by the OST against the NRC Source Material License. The EAB further held that the EPA complied fully with the Safe Drinking Water Act and the Administrative Procedure Act, denying all of the claims asserted in the appeal.
Although the Petitioners have appealed the reissued EPA final permits, the permits remain effective and allow enCore to proceed once the state permits are issued.
The OST appeal of the EPA Class III and Class V UIC permits is now combined with the appeal of the EPA issuance of the Aquifer Exemption currently pending before the 8th Circuit Court of Appeals.
In South Dakota, enCore is advancing work on the major state permits needed to operate the Dewey Burdock Project. The State Engineer had previously recommended approval of the Inyan Kara (#2686-2) and Madison (#2685-2) Water Rights. Based on recent discussions with the Department of Agriculture and Natural Resources (“DANR”), the most appropriate and expeditious path to advance water rights and resume the DANR Water Management Board hearings will be to provide an updated application which is being finalized. Similarly, the Company is also working to advance the DANR Large- Scale Permit to Mine approvals and resume hearings. DANR has recommended conditional approval of the Groundwater Discharge Plan and Large-Scale Permit to Mine. It should be noted that now that the Class V UIC disposal well permit has been issued, enCore has paused advancing the Ground Water Discharge Plan at this time as it is not operationally essential.
Mineral Resources
Key assumptions for the following Mineral Resource estimates are as follows:
•Mineral resources have been estimated based on the use of the ISR extraction method and yellowcake production and are based on 6,394 drill holes;
•Average density of 16.0 cubic feet per ton was used, based on historical sample measurements;
•Uranium price forecast is based on TradeTech’s Uranium Market Study 2023: Issue 4; and
•Price forecast, production costs and an 80% metallurgical recovery were used to estimate mineral resources.
Summary of Uranium Mineral Resources at the Dewey Burdock ISR Project as of December 31, 2025
Based on a metal price of $87.05/lb. U 3 O 8

Mineral Resources | Tons | Avg. GT | Avg. Grade (% U 3 O 8) | Avg. Thickness | lbs U 3 O 8
Measured | 5,419,779 | 0.73 | 0.13% | 5.56 | 14,285,988
Indicated | 1,968,443 | 0.41 | 0.07% | 5.74 | 2,836,159
Measured and Indicated | 7,388,222 | 0.66 | 0.12% | 5.65 | 17,122,147
Inferred | 645,546 | 0.32 | 0.06% | 5.87 | 712,624

Notes:
1.enCore reports mineral reserves and mineral resources separately. Reported mineral resources do not include mineral reserves.
2.The geological model used is based on geological interpretations on section and plan derived from surface drill hole information.
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3.Mineral resources have been estimated using a minimum grade-thickness cut-off of 0.20 ft% U 3 O 8.
4.Mineral resources are estimated based on the use of ISR for mineral extraction.
5.Inferred mineral resources are estimated with a level of sampling sufficient to determine geological continuity but less confidence in grade and geological interpretation such that inferred resources cannot be converted to mineral reserves.
There have been no changes to the Dewey Burdock Project Mineral Resource estimates for the year ended December 31, 2025 as compared to the year ended December 31, 2024.
Mining, Processing and Recovery Methods
The Company will mine uranium using ISR. An alkaline leach system of carbon dioxide and oxygen will be used as the extracting solution. Bicarbonate, resulting from the addition of carbon dioxide to the extracting solution, will be used as the complexing agent. Oxygen will be added to oxidize the uranium to a soluble +6 valence state.
A CPP and satellite will collect and process uranium. The CPP processing circuits will consist of ion exchange, elution, precipitation, de-watering, drying and packaging. The satellite facility will include an IX circuit and a resin transfer system to facilitate transfer of loaded resin by truck from the satellite to the CPP. The processing method is an industry standard and proven method that is most suitable for uranium processing and recovery. This method also has low environmental impact and results in a high purity product.
The CPP will be located on the Burdock property and the satellite will be located at Dewey property. The distance between the two facilities is approximately four miles.
Planned Work
For 2026, the Company plans to complete significant permitting and license milestones, including the 10 year renewal of the Source Material License, SUA-1600, with the NRC, and the advancement of state approvals of its water rights application and large mine permit. Since the EPA UIC well permits have been issued, management has decided not to pursue a discharge permit.
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Gas Hills Project, Natrona Co. and Fremont Counties, Wyoming
The Company owns a 100% interest in the Gas Hills Project located in the historic Gas Hills uranium district situated 45 miles east of Riverton, Wyoming. The Gas Hills Project consists of approximately 1,280 surface acres and 12,960 net mineral acres of unpatented lode mining claims, a state of Wyoming mineral lease, and private mineral leases, within a brownfield site which has experienced extensive development including mine and mill site production.
The following technical and scientific description of the Gas Hills Project is based in part on the Gas Hills Technical Report Summary. The Gas Hills Technical Report Summary was prepared in accordance with S-K 1300. The Gas Hills Project does not have known “Mineral Reserves” and is therefore considered under SEC S-K 1300 definitions to be an Exploration Stage Property.
Property and Operational Overview
The Company’s 100% percent owned Gas Hills Uranium Project is located approximately 45 miles east of Riverton, Wyoming in the historic Gas Hills Uranium District. The Gas Hills Project and the Gas Hills Uranium District are located along the southern extent of the Wind River Basin, near the northern edge of the Granite Mountains. The Company’s project properties, including the West Unit, Central Unit, Rock Hill, South Black Mountain, and Jeep properties, consist of 628 unpatented lode mining claims, one state of Wyoming mineral lease, one private mineral lease, and one private surface use agreement. Together the properties encompass approximately 360 surface acres and 12,960 mineral acres. The properties are located at latitude 42.7295°, longitude -107.6596° in Townships 32 and 33 North, Ranges 89, 90 and 91 West, 6th Principal Meridian, Fremont and Natrona Counties, Wyoming.
The U.S. federal government owns the minerals associated with the mining claims, the state of Wyoming owns the minerals and surface associated with the state lease, the South Pass Land and Livestock Company owns the minerals associated with the private mineral lease, and the Philp Sheep Company owns the surface associated with the private surface use agreement. The BLM manages the claims on behalf of the US federal government. The mining claims, State lease, and private mineral lease were assembled by Strathmore Resources (US) Ltd. (Strathmore) between April 2006 and September 2012 and sold to UColo on October 31, 2016. Title has remained in UColo’s name since that date and UColo is a subsidiary of the Company through Azarga Uranium’s acquisition of URZ (the parent company of UColo) in July 2018. The surface use agreement was entered into by UColo effective July 7, 2023.
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Ownership
In addition to the Gas Hills Project, the transaction included Strathmore’s claims and state mineral leases for the Juniper Ridge and Shirley Basin Properties.
St ate of Wyoming Lease
Strathmore entered into a ten-year lease with the State of Wyoming for Mineral Lease #0-42121 on April 2, 2007. The lease was subsequently transferred by Assignment from Strathmore to UColo on October 31, 2016. UColo renewed the lease before its 10-year expiration, extending the lease an additional ten years to April 1, 2027. The lease can be renewed, at UColo’s option, for unlimited additional 10-year periods as long as the terms and conditions of the lease have been met up to the time of applying to the State of Wyoming for renewal. The lease encompasses approximately 320 surface acres and 320 mineral acres in the NE¼, N½NW¼, and E½SE¼ of Section 36, Township 33 North, Range 90 West, 6th Principal Meridian, Fremont County, Wyoming. The lease grants to the State a royalty of 4% of the gross selling price of U3O8 or $5.00 per leased acre per year, whichever is more. No mineral resources discussed in this Annual Report are located on this lease.
Private Mineral Lease
Strathmore entered into a private mineral lease with South Pass Land and Livestock Company on July 28, 2010, for rights to minerals on the following two parcels of land: 40 mineral acres in the Jeep area in the SE¼ of Section 32, Township 32 North, Range 91 West, 6th Principal Meridian, Fremont County, Wyoming and 40 mineral acres in the West Unit area in the SW¼ of Section 19, Township 32 North, Range 90 West, 6th Principal Meridian, Fremont County, Wyoming. The mineral lease was transferred by Assignment and Assumption of Mineral Lease from Strathmore to UColo on October 31, 2016. UColo exercised its option to renew the lease for an additional 10 years in July 2020, by making the required payment. Unlimited 10-year renewals are available at UColo’s option for additional payments. The lease grants a 5% net proceeds royalty to the owner of the mineral properties. The surface is owned separately from South Pass Land and Livestock Company. An agreement for surface access at the West Unit is described below. Presently, there is no agreement for surface access at the Jeep parcel.
Private Surface Use Agreement
UColo entered into a private surface use and access agreement with Philp Sheep Company on July 7, 2023, to access and use approximately 40 surface acres in the West Unit located in the SW1/4 of Section 19, Township 32 North, Range 90 West, 6th Principal Meridian, Fremont County, Wyoming. The agreement allows exploring, prospecting, drilling, constructing, and plugging and abandoning up to 10 exploratory boreholes on the parcel. Access to Section 19 is provided across the SW¼ of Section 13, Township 32 North, Range 91 West, 6th Principal Meridian, Fremont County, Wyoming under the agreement. The term of the agreement is through November 7, 2026. Philp Sheep Company does not own the minerals in the parcel covered by the agreement. The minerals are owned by the South Pass Land and Livestock Company described above.
A 5% net proceeds royalty applies to 172 of the 628 claims as follows:
•A net proceeds royalty of 5% on 155 claims was granted by Quit Claim Deed from Strathmore to Elmhurst Financial Group, Inc. on October 31, 2007. One of the claims was relinquished during Strathmore’s ownership. The surviving 154 claims were sold to UColo and remain subject to the 5% net proceeds royalty.
•A 5% net proceeds royalty was granted by assignment from Strathmore to Blue Rock, on nine full claims and on the southern 720 feet of nine additional claims. The 18 claims were sold to UColo and remain subject to the 5% net proceeds royalty.
• The other 456 claims are not subject to royalties or other encumbrances.
UColo has the possessory right to explore, develop and produce from the unpatented lode mining claim areas and must pay an annual maintenance fee to the BLM of $200.00 per claim on or before September 1 each year. Surface use at the location of the mining claims on BLM lands is allowed subject to Title 43 of the US Code of Federal Regulations Subpart 3809 and requires permitting by both the BLM and the State of Wyoming Department of Environmental Quality, Land Quality Division “WDEQ-LQD”.
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Infrastructure
Extensive production in Wyoming of minerals (coal, trona, uranium) and oil/gas has provide a highly skilled labor force in the region. Population centers within two hours of the Gas Hills Project include Casper, Riverton, Lander, and Rawlins, where equipment and supplies may be obtained. Paved roads from these towns and cities extend to the edge of the Gas Hills Project area. Access and haul roads within the Project are graded gravel and are maintained by the State, County, and mining companies operating in the area. Functioning power lines, natural gas lines, telephone lines, and fiber optic cable are present on and near enCore’s properties. Several wells producing water for domestic and industrial use are also on or close to enCore’s properties. Total capital cost estimates are $120.2 million for the Gas Hills Project, which includes design and permitting, CPP, disposal well, wellfields and transfer pipeline construction and other general and administrative costs.
Geology, Mineralization and Deposit
In the Gas Hills Uranium District, (“Gas Hills”), lower Tertiary rocks unconformably overlie folded and faulted Mesozoic and older rocks (Figure 7.3). The Wind River Formation is conformably overlain by tuffaceous sandstones of the Eocene Wagon Bed Formation.
The Puddle Springs Arkose member of the Wind River Formation is the host rock for the uranium deposits at the Gas Hills Project. It consists of poorly consolidated arkosic sandstone and conglomerate with thin discontinuous interbeds of mudstone. The Puddle Springs arkose was deposited rapidly by northward-flowing braided streams to form coalescing piedmont alluvial fans.
Drilling in the west Gas Hills indicates that the favorable arkosic sandstone grades into unfavorable silty facies. A local sandstone facies has been found within the silty facies, and a small area containing uranium (Jeep deposit) has been found in the sandstone facies. Thus, the favorable host for mineralization in the above-mentioned deposits is bounded on the north by an erosional pinch out; on the east by a change of facies to an unfavorable silty sandstone host; on the south by a subsurface onlap pinch out; and on the west by change of facies to an unfavorable silty sandstone host.
Uranium mineralization in the Gas Hills is present in bodies usually referred to as “rolls”. In vertical cross section they are irregularly crescent or “C” shaped. Rolls are the result of oxidized and soluble uranium being transported by ground water to a location within a permeable sandstone host where a reaction within a reducing environment occurs and insoluble reduced, uranium minerals are deposited. The contact between oxidized and reduced conditions is the “roll front”.
Uranium deposits in the Gas Hills were formed by the classic Wyoming-type roll-fronts. Roll-fronts are irregular in shape, roughly tabular and elongated, and range from thin pods and a few feet in width and length, to bodies several hundred or thousands of feet in length. The deposits are roughly parallel to the enclosing beds but may form rolls that cut across bedding. Roll-front deposits are typified by a C-shaped morphology in which the outside of the C extends down-gradient in the direction of historic groundwater flow and the tails extend up-gradient of historic groundwater flow. Tails are typically caught up in the finer sand and silt deposits that grade into over and underlying mudstones, whereas the heart of the roll-front (higher grade mineralization) lies within the more porous and permeable sandstones toward the middle of the fluvial deposits.
History
The Gas Hills was one of the major uranium mining and production regions in the United States. Between 1953 and 1988, many companies explored, developed and produced uranium in the area, including in the Gas Hills Project area. Three uranium mills operated in the district and two others nearby were also fed by ore mined from Gas Hills. Cumulative production from the Gas Hills is in excess of 100 million lbs of uranium, mainly from open-pit mining, but also from underground mining and ISR.
Mine production did occur adjacent to and in the vicinity of the Gas Hills Project; however, the areas for which mineral resources are defined are unmined. The last mill production in the Gas Hills occurred in 1988 and extensive mill site and mine reclamation occurred from the late 1980s to now. However, Wyoming remains the largest current uranium producer in the United States and there are numerous uranium projects in the state. More than 100,000 exploration and development holes were drilled in the Gas Hills from the mid-1950s to the mid-1980s. Since 1990, a few hundred drill holes have been drilled, nearly all by Strathmore and Cameco.
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Permitting and Licensing
Prior to significant construction and mining, several permits/licenses from federal, state, and local agencies will be required as follows:
Federal
•EPA – Aquifer Exemption for UIC Class III wells and UIC Class I disposal wells (as necessary) and Subpart W Pond Construction Permit for the holding pond.
•BLM – Environmental Assessment (EA) and Approval of the Plan of Operations.
State
•Wyoming Department of Environmental Quality Uranium Recovery Program “WDEQ-URP” – Source and Byproduct Material License.
•WDEQ-LQD – Permit to Mine.
•WDEQ Water Quality Division – UIC Class I Permit for deep well injection of wastewater generated from wellfield bleed and other plant processes, and Storm Water Discharge Permit which allows for surface discharge of storm water.
•WDEQ-Air Quality Division – Air Quality Division, Chapter 6, Section 2, New Source Permit Authorization to Construct. • Wyoming State Engineer’s Office “SEO” – Various groundwater appropriation permits for ISR of uranium.
Local
•Fremont County Septic system.
Since a large portion of the project lies over federal surface, the BLM will complete the National Environmental Protection Act (“NEPA”) analysis for this project which will be required to approve the BLM Plan of Operation. Since the footprint of this project is less than 640 acres, BLM regulations indicate that the NEPA analysis should be an Environmental Assessment level review. Should BLM decide to pursue a full Environmental Impact Statement a much more detailed analysis of potential project impacts will be required at the Gas Hills Project.
WDEQ-URP license preparation and review process will take approximately two years to complete. The review will include an opportunity for public comment. WDEQ-LQD, will review the permit to mine application pursuant to Noncoal Chapter 11 Rules and Regulations and will provide opportunities for public comment. The LQD review will also likely take about two years which will happen in parallel with the URP review. Following permit to mine approval, an aquifer exemption from the EPA Region 8 will be requested. The EPA will review the LQD’s request against UIC Program requirements found in 40 CFR Parts 144 and 146 to ensure compliance. If the EPA determines the operation will be in compliance, the agency will issue an aquifer exemption which allows mining within a defined portion of the uranium host aquifer.
Mineral Resources
The mineral resource estimates are based on radiometric equivalent uranium grades % eU 3 O 8. A minimum 0.02% U 3 O 8, minimum 1.0-foot thickness, and minimum GT of 0.10 was used in the estimations along with a bulk dry density of 16 cubic feet per ton. Resources were estimated using the GT contour method, which is industry standard for this type of deposit. The GT was determined for each drill hole by major stratigraphic horizon, then the GT was summed separately for each mineralized sub-horizon for intercepts meeting the cutoff criteria. Contours were drawn in two-dimensional space around horizon intercepts, allowing projection up to 100 feet across a mineralized trend and up to 600 feet along the mineralized trend.
Average GT for each contour was calculated one of two ways depending on if the contour was the highest GT contour or if it contained another, higher GT contour. If the contour was the highest GT contour, all GT values within the contour were averaged, then averaged with the value of that GT contour. If the contour contained another higher contour, the average GT was the average of the upper and lower GT contour values.
Pounds of uranium for each contour were calculated by multiplying the contour area by GT for the contour and applying the conversion constant and dividing by bulk density factor ((Area x Avg GT x 20)/16 = Pounds). Tonnage was calculated by multiplying composited contour thickness by contour area to get cubic feet, then converting to tonnage by applying the density factor (Thickness x Area/16).
The 0.10 GT base case cutoff was selected by meeting economic criteria for both ISR and open pit/heap leach methods differentiated on the relative location to the water table. Resources labeled “ISR” meet the criteria of being sufficiently
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below the water table to be amenable by ISR methods and as well as also meeting other hydrogeological criteria. “Non-ISR” resources include those generally above the natural water table, which would typically be mined using open pit methods.
Mineral resources were classified as measured, indicated, and inferred based on the distance to the nearest drilling intercept to measure drilling density. To be classified as measured resources, the contour must fall within 100 feet of a mineralized drill hole intercept in that horizon. Indicated resources must fall between 100 and 250 feet from the nearest mineralized intercept in that horizon. Inferred resources must be within 600 feet of a mineralized intercept in that horizon.
The GT contours were divided and classified based on area contained within each of the distance boundaries from drill hole intercepts. After classifying resources based on distance from drilling, further consideration was given to applicable mining methods for each pod. Reclassification of resource was determined based on local water table levels at each resource pod and the level of detail of hydrogeologic understanding.
As of December 31, 2025, only the Central Unit has had groundwater flow modeling completed. All other ISR resources which met the measured criteria for ISR drilling density were classified as indicated resource until more detailed hydrologic studies to support ISR are conducted on these resource areas.
The cutoff used for mineral resource classification was a minimum 0.02% eU3O8, minimum 1.0-foot thickness, and minimum 0.10 GT. These criteria were determined to meet the criteria for “reasonable prospects for economic extraction” for both ISR and open pit heap/leach mining methods. The GT cutoff of 0.10 GT is also consistent with previous historic resource estimation in the area. The average grade of ISR resources in this estimate at a 0.10 GT cutoff met economic criteria for ISR extraction.
When drawing GT contours, the maximum allowable GT was set at 7.0. Any drilling intercept with a higher GT was included in the 7.0 GT contour and assigned that value.
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Measured and Indicated Mineral Resource Summary as of December 31, 2025:
(Based on a metal price of $87.00/lb. U 3 O 8)

Pounds | Tons | Average Grade | Average Grade % | Average Thickness | Average GT
GT cutoff |  |  |
Measured | 2,051,000 |  | 994,000 |  | 0.10 | % | 5.35 | 0.55 |
Indicated | 8,713,000 |  | 6,031,000 |  | 0.07 | % | 6.13 |  | 0.44 |
Total Measured and Indicated | 10,764,000 |  | 7,025,000 |  | 0.08 | % | 6.05 |  | 0.46 |
ISR Only (GT cutoff 0.10) |  |  |
Measured | 2,051,000 |  | 994,000 |  | 0.10 | % | 5.35 | 0.55 |
Indicated | 5,654,000 |  | 2,835,000 |  | 0.10 | % | 4.92 |  | 0.49 |
Total Measured and Indicated | 7,705,000 |  | 3,829,000 |  | 0.10 | % | 4.99 |  | 0.50 |
Non -ISR Only (GT cutoff 0.10) |  |  |
Indicated | 3,059,000 |  | 3,196,000 |  | 0.05 | % | 8.60 |  | 0.41 |
Total Measured and Indicated | 3,059,000 |  | 3,196,000 |  | 0.05 | % | 8.60 |  | 0.41 |

Notes:
1. Mineral resources as defined in 17 CFR § 229.1300.
2. All ISR only resources occur below the static water table.
3.The point of reference for mineral resources is in-situ at the Gas Hills Project.
4. Mineral resources are not mineral reserves and do not have demonstrated economic viability.
5. An 80% metallurgical recovery factor was considered for the purposes of the economic analysis.
6.Totals may not sum due to rounding.
Inferred Mineral Resource Summary as of December 31, 2025:
Based on a metal price of $87.00/lb. U 3 O 8

Pounds | Tons | Average Grade | Average Grade % | Average Thickness | Average GT
GT cutoff 0.10) |  |  |
Inferred | 490,000 |  | 514,000 |  | 0.05 | % | 6.16 | 0.29 |
ISR Only (GT cutoff 0.10) |  |  |
Inferred | 428,000 |  | 409,000 |  | 0.05 | % | 5.94 | 0.31 |
Non -ISR Only (GT cutoff 0.10) |  |  |
Inferred | 62,000 |  | 105,000 |  | 0.03 | % | 7.01 |  | 0.21 |

Notes:
1.Mineral resources as defined in 17 CFR § 229.1300.
2.All ISR only resources occur below the static water table.
3.The point of reference for mineral resources is in-situ at the Gas Hills Project.
4.Mineral resources are not mineral reserves and do not have demonstrated economic viability.
5.Totals may not sum due to rounding.
There have been no changes to the Gas Hills Project Mineral Resource estimates for the year ended December 31, 2025 as compared to the year ended December 31, 2024.
Mining, Processing and Recovery Methods
enCore plans to use the ISR mining technique with a low pH lixiviant at the Project. Gas Hills was one of the major uranium mining and production regions in the USA with cumulative production in excess of 100 million pounds of uranium, mainly from open-pit mining, but also from underground and ISR mining methods. This historical production demonstrated the host Wind River Formation sandstones and the hydrological conditions to be suitable for ISR production.
ISR is employed because this technique allows for the low cost and effective recovery of roll front mineralization. An additional benefit is that ISR is relatively environmentally benign when compared to conventional open pit or underground recovery techniques. ISR does not require the installation of tailings facilities or require significant surface disturbance.
ISR operations consist of four major solution circuits, ion exchange to extract uranium from the mining solution, an elution circuit to remove uranium from the IX resin, a yellowcake precipitation circuit, and a dewatering, drying, and packaging circuit.
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Planned Work
In 2026, the Company plans to complete environmental data collection necessary to prepare an application for a source material license and a permit to mine with the State of Wyoming. Additionally, the Company expects to begin preliminary work on an application for a plan of operations from the BLM.
Quality Assurance and Quality Control Program
STX Integrated Project
Signal Equities, LLC (“Signal Equities”), had written procedures for the collection of drill data including lithological logging, natural gamma logging, PFN logging, and also for data entry into databases and GIS. All drill hole data are now maintained at enCore’s corporate office in Corpus Christi, Texas. For the initial exploration of the Brevard and Brown properties, Signal Equities previously had written procedures for the collection of drill data including lithological logging, natural gamma logging, and PFN logging, and also for data entry into databases and GIS. All data were stored on a secure server at the Signal Equities corporate office in New Braunfels, TX, with a full copy backup at a secure off-site contract data storage facility. enCore has since acquired and retains all data collected by Signal Equities.
For the South Texas Technical Report Summary and related Mineral Resource estimates, the QP reviewed PFN logs, gamma logs and drilling records for each drill hole used to calculate mineral resources. The QP corrected errors that were identified in the previous owner’s PFN calibration calculations and grade calculations using the raw logging data and known constants such as hole diameter and published DOE test pit grade values. Using the carefully verified and corrected data, the QP checked the GT contour and GIS data provided by enCore. Approximately 75% of all the drill hole data used to prepare the mineral resource estimate were validated by checking the corresponding PFN logs.
Alta Mesa and Mesteña Grande Projects
enCore maintains written standard operating procedures for drilling, lithological logging and geophysical logging. Virtually all drilling completed by enCore for the purposes of exploring and resource development consists of rotary drilling. enCore collected rotary mud samples for lithological logging by 5-foot increments. Lithological logs of the samples are completed in the field by geologists following the standard written procedures and using standard lithological log forms.
Drill hole locations are staked in the field using a Trimble hand-held GPS capable of sub-meter accuracy. The holes are surveyed prior to drilling. Field surveys of 8 exploration drill holes and one well with the Alta Mesa GPS unit as a check. The well location was within 0.13 feet of the recorded location. The drill hole locations deviated from the reported location by 1.33 to 11.28 feet with an average variance of 6.06 feet. It is this author’s conclusion that the majority of the variance is due to the driller not accurately locating the drill hole at the staked location rather than the accuracy of the GPS unit, and thus, recommends that the drill hole location procedure be modified to include both pre and post drilling surveys of the drill holes. Past drilling practices were conducted in accordance with industry standard procedures and the most recent drilling conducted by enCore, confirmed historical drill results in previously intersected mineralization for thickness, grade and location.
Sample Preparation, Analysis, and Security Sample Methods
Samples are collected from drill holes for drill cuttings, down hole geophysics and core samples. Cores are the only samples that are prepared and dispatched to an analytical or testing laboratory. Cuttings and geophysical data are prepared and analyzed in house. Sampling, sample preparation and security are described in the following sections.
Down Hole Geophysical Data
Continuous measurement of down hole geophysical properties is measured from total hole depth to surface. Geophysical data is collected using logging probes equipped with gamma, resistivity, SP, PFN and down hole survey logging tools. This suite of logs is ideal for defining lithologic units in the subsurface. The resistivity and spontaneous potential tools are used to define lithology by qualitative measurements of water conductivities.
The gamma tool provides an indirect measurement of uranium content. Gamma radiation is measured in one-tenth foot intervals and converted to gamma ray readings measured in counts-per-second into %-eU 3 O 8. Equivalent percent uranium grades are reported in one-half foot increments.
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The PFN tool provides a direct measurement of uranium around the borehole. The pulsed neutrons sources electronically generate neutrons which causes fission of U235 in the formation. Tool detectors count epithermal and thermal neutrons returning from the formation providing a direct measurement of formation uranium content.
Drill holes are also down hole surveyed measuring deviation by azimuth and declination, providing a holes true bottom location and depth.
enCore samples all drill holes with gamma, resistivity, spontaneous potential and down hole survey. Due to cost and time, enCore only PFN samples mineralized intervals with gamma measured grades above 0.02 %-eU 3 O 8.
To ensure geophysical data quality control, tools are calibrated at a Department of Energy test pit in George West, Texas. PFN tools are calibrated using onsite test pits. Test pits have known uranium source concentration and using industry calibration procedures tools are calibrated, to ensure consistent measurement and reporting of uranium concentrations from US deposits.
Drill Cuttings
Drill cuttings are collected at 5-foot intervals while drilling. Samples are arranged on the ground in order of depth to show changes in lithology and color. Lithology and color are recorded on a lithology log for entire hole depth. Particular attention is paid to color in the mineralized sand to assess oxidation/reduction potential. Cuttings are not chemically assayed as drilling mud will contaminate samples and precise sample location or depth cannot be determined from cuttings.
Core Samples
Core samples are collected to conduct chemical analyses, metallurgical testing, and testing of physical parameters of lithologic units. Retrieved cores are measured to determine core recovery. Cores are also washed, photographed and described. In preparation for laboratory analysis, to maintain moisture content and prevent oxidation, core is wrapped in plastic, boxed and frozen or iced.
Laboratory Analysis
When core is collected in the field, it is immediately rinsed, measured for length, split in half and photographed. One half of the core is sampled in 1-foot increments and either wrapped in plastic or vacuum sealed to maintain moisture content and prevent oxidation, boxed, frozen or iced and transferred to an analytical or testing laboratory.
The other half of core is split into quarters. One quarter is preserved as previously described, and the other quarter is used to describe lithologic characteristics (i.e., lithology, color, grain size and fraction). Core preserved for testing is used for leach amenability determination. Leach amenability studies are intended to demonstrate that the uranium mineralization is capable of being leached and determination of the optimal mining lixiviant chemistry. Typically, sodium bicarbonate is used as the source for a carbonate complexing agent to form uranyldicarbonate (UDC) or uranyltricarbonate ion (UTC), and Oxygen or Hydrogen peroxide are used as the uranium-oxidizing agent. Tests are not designed to approximate in-situ conditions (permeability, porosity, pressure) but are an indication of an ore’s reaction rate and potential uranium recovery.
enCore adheres to security measures using Chain of Custody procedures to ensure the validity and integrity of samples through the analysis process. enCore may sample and transfer duplicate samples to assess reliability and precision of analytical results for quality control of sample collection or laboratory analysis procedures.
Core samples are submitted to an analytical or testing laboratory that is certified through the National Environmental Laboratory Accreditation Program, which establishes and promotes mutually acceptable performance standards for the operation of environmental laboratories. The standards address analytical testing, with state and federal agencies and serve as accrediting authorities with coordination facilitated by the EPA to assure uniformity.
Dewey-Burdock Project
Past drilling practices were conducted in accordance with industry standard procedures and the most recent drilling conducted by Powertech, confirmed historical drill results in previously intersected mineralization for thickness, grade and location. The QP of the Dewey Burdock Technical Report Summary is knowledgeable of the 2007 and 2008 work and technical participants who were responsible for the work.
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Data Verification
Numerous companies have worked on the Dewey Burdock Project since the 1950’s and as a result numerous data sets of different vintages exist. enCore has a nearly complete data set for the Project. The QP reviewed geophysical, core and hydrogeologic technical data. Technical data is stored in digital format for geologic interpretation and modeling. The QP also reviewed geologic interpretations and the resultant models, in the form of cross-sections, isopach and structural maps, and uranium roll front deposit models.
The work done by enCore and previous operators to verify historical records does validate Dewey-Burdock Project information. Data are available for over 6,300 drill holes and for approximately 24% of the holes, enCore does not have the actual geophysical logs. The company does have collar location and mineralization data, for all holes, and has used data from surrounding holes to verify data for holes with missing geophysical logs. Considering drilling density, enCore’s approach to data verification is a reasonable means to confirm data validity; however, not having data in hand does limit knowledge of precise location of down hole information.
Gas Hills Project
For 2011 and 2012, drilling security practices involved: awareness of chain-of-custody issues, limited access to logging tools through locked storage as approved by the NRC, and continuing calibration of logging tools to assure that no tampering has occurred. All drill hole samples were in locked storage until sent out for laboratory testing. Drill cutting samples were generally not preserved and it was typical for the mine operators to assay drill samples at their on-site laboratories.
Data Verification
Data sources reviewed for the estimation of uranium mineral resources for the Gas Hills Project include radiometric equivalent data (eU 3 O 8) for 4,570 drill holes (4,056 pre-2007), eU3O8 data and PFN assay data for 272 drill holes completed from 2007 to 2013, and eU 3 O 8 and core data for one core hole completed in 2024. For the 2011-2012, drilling programs, down hole geophysical logging using the PFN tool was completed with Strathmore’s PFN logging truck and independently confirmed by GAA Wireline Services.
Extensive verification work was previously completed for holes drilled pre-2007 in the 2017 mineral estimate. The Mineral Reserves estimate for the Gas Hills Project used the results of the 2007 to 2013 drilling as part of the verification procedures on the pre-2007 drilling.
Non-Material Properties
The Company holds a number of other Exploration Stage Properties that the Company has determined are not material to its business. In total the properties total an aggregate of approximately 360,000 acres of mineral claims, mineral leases, and fee minerals:
•Metamin Properties, Arizona, Utah and Wyoming. Through its subsidiary Metamin Enterprises US Inc. (“MEUS”), the Company holds various prospective uranium mining properties located in the States of Arizona, Utah and Wyoming.
•Kingsville Dome, Texas. The Kingsville Dome property is located in Kleberg County and is situated on several tracts of land leased from third parties. The property is situated approximately eight miles southeast of the city of Kingsville. The project is comprised of numerous mineral leases from private landowners, covering an area of approximately 2,434 gross and 2,227 net acres of mineral rights. The Kingsville Dome CPP is a licensed ISR production facility located on 15 acres of Company-owned property.
•Vasquez Project, Texas. The Vasquez project is located in Duval County. The Vasquez property consists of a mineral lease on 1,023 gross and net acres.
•Dewey Terrace Project, Wyoming. This project consists of approximately 1,874 acres of surface rights and approximately 7,514 acres of net mineral rights. The Dewey Terrace Project is located adjacent to the Dewey Burdock Project.
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•Juniper Ridge Project, Wyoming. The Juniper Ridge project in Carbon County consists of approximately 640 surface acres and 3,240 net mineral acres of unpatented lode mining claims and a State of Wyoming mineral lease and is located within a brownfield site which has experienced extensive exploration, development, and mine production.
•Centennial Project, Colorado. The Centennial Project in Weld County is comprised of approximately 523.21 acres of surface rights and 237.09 acres of net mineral rights. Approximately 5,760 acres of minerals rights were conveyed back to Anadarko Petroleum Corporation by Special Warranty Deed in January 2025, significantly reducing the project size. The Company intends to allow current leases to expire, and maintain existing mineral rights currently owned by the Company in fee.
•Aladdin Project, Wyoming. The Aladdin Project is comprised of private leases that cover approximately 5,166 acres of surface rights and 4,712 acres of net mineral rights. The Aladdin Project is 80 miles northwest of the Dewey Burdock Project.
•Tacubaya Project, Texas. The Company holds over 5,900 acres of private land consisting of mineral and surface leases located immediately adjacent to, and east of, the Alta Mesa Project.
•Other Properties: The Company holds the Shirley Basin Project in Wyoming the JB Project in Colorado and Utah, and the Ticaboo project in Utah which covers over 20,000 acres of private land.
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Seasonality
The timing of our uranium concentrate sales are dependent upon factors such as extraction results from our uranium recovery activities, cash requirements, contractual requirements and perception of the uranium market. As a result, our sales are neither tied to nor dependent upon any particular season. In addition, our ability to extract and process uranium does not change on a seasonal basis.
Sustainability Principle s
The long-term success of enCore requires the integration of sustainability into all aspects of its business. The Company announced on October 21, 2024, the release of its inaugural Sustainability Report , which is maintained on the Company’s website, at www.encoreuranium.com.
Land Tenure
The Company’s land holdings in the United States are held either by leases from the fee simple owners (private parties or the State) or unpatented mining claims located on property owned and managed by the U.S. Federal Government. Annual fees must be paid to maintain unpatented mining claims, but work expenditures are not required. Holders of unpatented mining claims are generally granted surface access to conduct mineral exploration and extraction activities. However, additional permits and plans are generally required prior to conducting exploration or mining activities on such claims.
Government and Environmental Regulations
Government Regulations
The Company’s properties and facilities are subject to extensive laws and regulations which are overseen and enforced by multiple federal, state and local authorities. These laws govern exploration, construction, extraction, recovery, processing, exports, various taxes, labor standards, occupational health and safety, waste disposal, protection and remediation of the environment, protection of endangered and protected species, toxic and hazardous substances, and other matters. Uranium minerals exploration, extraction, recovery, and processing are also subject to risks and liabilities associated with the perceived potential for impacts to the environment and disposal of waste products occurring as a result of such activities.
Compliance with these laws and regulations may impose substantial costs on the Company and may subject the Company to significant potential liabilities. Changes in these regulations or changes in regulatory attitudes or interpretations could require the Company to expend significant resources to comply with new laws or regulations, attitudes or interpretations relating thereto, or changes to current requirements and could have a material adverse effect on the Company’s business operations. However, compliance with government regulations generally, including but not limited to environmental regulations, is an integral part of the Company’s day-to-day business and impacts virtually all the Company’s capital expenditure and operating decisions at its facilities, as the Company’s facilities and operations must comply with this extensive array of environmental, health and safety laws and regulations. The costs of compliance with these laws and regulations are therefore well understood and assumed by the Company in all its capital budgeting decisions, project analyses and cost and earnings projections. As all of the Company’s competitors in the uranium mining industry in the United States face the same or similar regulatory requirements, the Company does not believe its need to comply with this extensive array of laws and regulations materially affects the Company’s competitive position within the U.S. uranium mining industry.
Environmental Regulations
Our operations where exploration, development and operations are taking place, are subject to extensive laws and regulations which are overseen and enforced by multiple federal, state and local authorities. These laws and regulations govern exploration, development, various taxes, labor standards, occupational health and safety including radiation safety, waste disposal, underground source of drinking water, protection and remediation of the environment, protection of endangered and protected species, toxic and hazardous substances and other matters. Uranium minerals exploration is also subject to risks and liabilities associated with pollution of the environment and disposal of waste products occurring as a result of mineral exploration.
Compliance with these laws and regulations imposes substantial costs on us and may subject us to significant potential liabilities or impacts on operations or project development. Changes in these regulations could require us to expend significant resources to comply with new laws or regulations or changes to current requirements and could have a material
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adverse effect on our business operations. Compliance with all current regulations, including but not limited to the environmental and safety regulatory schemes, is an integral part of our day-to-day business, management and staff commitment and expenditures. The costs attendant to compliance are understood and routinely budgeted and are generally comparable to those of other U.S. uranium companies and other natural resources companies in the United States and Canada. It should be noted that environmental protections and regulatory oversight thereof vary significantly outside North America, particularly in Kazakhstan and Russia, where state-owned enterprises operate with only limited regulatory oversight related to environmental and worker safety.
Mineral exploration and development activities, as well as our uranium recovery operations, are subject to comprehensive regulations which may cause substantial delays, restrictions or require capital outlays in excess of those anticipated, causing an adverse effect on our business operations. Mineral exploration operations are also subject to federal and state laws and regulations that seek to maintain health and safety standards. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal and state authorities may be changed and any such changes may have material adverse effects on our activities. Mineral recovery operations are subject to federal and state laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. The posting of a performance bond and the costs associated with our permitting and licensing activities require a substantial budget and ongoing cash commitments. In addition to pursuing ongoing permitting and licensure for new projects and additions to our existing projects, these expenditures include ongoing monitoring (e.g., wildlife, groundwater and effluent monitoring) and other activities to ensure regulatory and legal compliance, as well as compliance with our permits and licenses.
We believe that we comply in all material respects with all federal, state and local applicable laws and regulations which govern environmental quality and pollution control. The appropriate regulatory agencies do conduct routine and regular inspections of activities by the Company at all of its operating and past operating sites, and to date, the Company has not been notified of any material non-compliance that would require any form of financial penalty or operating restriction.
Licenses and Permits
In Texas, the TCEQ regulates uranium recovery and issues the necessary licenses and permits. A Radioactive Material License issued by TCEQ covers the Rosita, Kingsville Dome and Vasquez projects, and it was renewed in October 2025. Each site also has Class I non-hazardous injection permits for operation of waste disposal wells on site, which are also regulated by the TCEQ. All permits for the disposal wells are active.
The Rosita Project includes four TCEQ PAAs. Production areas 1 and 2 are depleted, and groundwater restoration has been completed to regulatory standards. Production areas 3 has been partially depleted by previous uranium extraction operations that were shut in in 2008. Production Area 5 is currently undergoing groundwater restoration. In 2013, enCore completed the final phase of TCEQ required stabilization in production areas 1 and 2.
The Alta Mesa Project is a fully licensed and constructed ISR project. The current RML and Class III UIC Permit are in timely renewal. Production Areas 1 through 4 have been depleted and the groundwater in Production Area 1 has been restored. Production Areas 5 and 6 have been partially extracted and will be restarted with future extraction operations. Production Area 7 is currently undergoing uranium extraction operations. The Alta Mesa Project has two fully permitted Class I non-hazardous injection permits for the operation of two disposal wells on site.
The Company’s Upper Spring Creek – Brown Uranium Project is currently partially permitted. It currently has an aquifer exemption and a Class III Underground Injection Control Permit.
Air Emissions
Our operations are subject to local, state and federal regulations for the control of emissions of air pollution. Major sources of air pollutants are subject to more stringent, federally imposed permitting requirements. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources. In Texas, the TCEQ issues an exemption for those processes that meet the criteria for low to zero emission by issuing a permit by rule.
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Water Management
We commit our management team, employees and contractors to be good stewards of the water it utilizes in all parts of its operations. From exploration to restoration, water is the critical factor for ISR projects and responsibly managing that water is crucial to our business.
At all our ISR projects the ore hosted groundwater does not meet either primary or secondary drinking water standards and should only be used for industrial or agricultural use without proper treatment.
Water consumption at our ISR projects is natural groundwater. During the recovery process, water is pumped from the ore hosted aquifer and piped to the satellite facility. The groundwater is filtered for solids, stripped of uranium, and then largely re-injected or recirculated back into the same aquifer it was recovered from. This recycling process is an advantage of ISR extraction compared to other methods such as conventional or open pit mining operations that may require significant groundwater de-watering to facilitate safe mining.
In order to ensure appropriate water management, and to ensure our team can continuously make decisions to reduce our water usage, we closely monitor our water consumption. We are identifying ways to reduce water consumption on an ongoing basis.
Compliance with the Clean Water Act
The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding the discharge of wastes, including mineral processing wastes, into waters of the United States; a term broadly defined. Permits must be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of hazardous substances and other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff. Management believes that we are in substantial compliance with current applicable environmental laws and regulations. The Company has no discharges that are regulated by the CWA at any of its current and planned operations.
Smaller Reporting Company Status
We are a “smaller reporting company” as defined in Regulation S-K under the Securities Act and may elect to take advantage of certain of the scaled disclosures available to smaller reporting companies.
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Item 1A. Risk Factors
T he Company is subject to risks, certain of which are described below. The occurrence of any one or more of these risks or uncertainties could have a material adverse effect on the value of any investment in the Company and the financial condition or operating results of the Company. Additional risks and uncertainties not presently known to the Company or that the Company currently deems immaterial may also impair the Company’s business operations. Due to the nature of the Company and its business, investors should carefully consider all such risks, including those set out in the discussion below, together with the other information in this Annual Report and our other filings with the SEC and Canadian Securities Administrators, together with the other information in this Annual Report and our other filings with the SEC and Canadian Securities Administrators.
Summary Risk Factors
The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed description of each risk factor contained below.
•our history of negative operating cash flows and our ability to develop or maintain positive cash flow from our extraction activities and the ability to obtain additional financing, if needed, in connection with implementation of business and strategic plans;
•risks associated with our expansion-by-acquisition strategy;
•our properties do not contain Mineral Reserves and some of our properties, projects and facilities may not be economic within a reasonable time period or at all;
•our reliance on key personnel, contractors and experts;
•conflicts of interest of our directors and officers;
•risks associated with exploration of, development of, and extraction from mineral properties;
•our reliance on third party drilling contractors, including an increased risk of loss, weather related risks or underutilization of drilling rigs;
•risks inherent to mineral exploration and extraction;
•the commercial viability of economic extraction of minerals from uranium deposits;
•the subjectiveness and uncertainty of estimations of Mineral Resources;
•future mineral extraction estimates may not be achieved;
•estimates of commodity prices used in preliminary economic assessments may never be realized;
•requirements to obtain or retain key permits to advance or achieve extraction;
•involvement of external groups, including Native American tribes, or non-governmental organizations, in the permitting process;
•challenges to title of our mineral property interests;
•our ability to attract, retain, train, motivate, develop and transition skilled employees;
•existing competition and geopolitical changes in the competitive landscape;
•public opinion and perception of nuclear energy;
•volatility in market prices of uranium;
•applicable laws, regulations and standards, including environmental protection laws and regulations;
•our ability to raise equity or obtain debt financing, including obtaining additional financing on acceptable terms when needed;
•accuracy of extraction, capital and operating cost estimates;
•ability of novel mining methods for extraction to yield anticipated results;
•the need for technical innovation and risk of obsolescence;
•availability of a public market for uranium, including global demand and supply;
•changes to and uncertainty in U.S. trade policy, tariff and import/export regulations;
•risks related to our operations on federal lands, including potential designation of national monuments or withdrawal or permits;
•risks related to our Alta Mesa joint venture;
•taxation implications of U.S. holders because the Company may be a passive foreign investment company;
•potential dilution if we issue additional common shares or securities convertible into common shares, such as our 5.50% convertible senior convertible due 2030 (the “Convertible Senior Notes”) and the related capped call transactions;
•price volatility of our common shares;
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•our expectation to not declare or pay dividends;
•reliance on information technology systems and cybersecurity risks;
•the time and resources necessary to comply with corporate governance practices and securities rules and regulations in the United States and Canada;
•our management’s ability to maintain effective internal controls;
•our remediation plan and ability to remediate the material weaknesses in our internal controls over financial reporting;
•potential lack of access to enforcement of civil liabilities against the Company, its directors or its officers;
•our ability to protect our proprietary data, technology and intellectual property;
•changes in climate conditions; and
•other risks described in this Annual Report, as more particularly described herein.
Risks related to enCore’s Business and Operations
We are an exploration stage company with a history of negative operating cash flows and we may never develop or be unable to maintain positive cash flow from our mining activities.
For the year ended December 31, 2025, enCore had negative operating cash flow and will require significant cash and/or alternative financing arrangements in order to develop its assets and meet its ongoing general and administrative costs and exploration commitments and to maintain its mineral property interests, which may require working capital and/or project financing in the future. As an exploration stage company, the Company’s operations to date have been funded primarily from debt and equity financings. As a result of the expenses to be incurred by the Company in connection with its business objectives for the development of the Company’s material projects, the Company anticipates that negative operating cash flows could continue for the foreseeable future. Accordingly, the Company will require substantial additional capital in order to fund its future exploration and development activities for its material projects. The Company does not currently have any additional arrangements in place for this funding and there is no assurance that such funding will be achieved when required. Any failure to obtain additional financing on favorable terms or failure to achieve and maintain profitability and positive operating cash flows will have a material adverse effect on enCore’s financial condition and results of operations.
We may need additional financing in connection with the implementation of our business and strategic plans from time to time.
The exploration, construction, development and acquisition of mineral properties and the ongoing operation of mines and other facilities requires a substantial amount of capital and may depend on our ability to obtain financing through joint ventures, debt financing, equity financing or other means. Accordingly, we may need additional capital in order to take advantage of further opportunities or acquisitions. Our financial condition, general market conditions, volatile uranium markets, volatile interest rates, legal claims against us, a significant disruption to our business or operations, or other factors may make it difficult to secure financing necessary for the expansion of mining activities or to take advantage of opportunities for acquisitions. Further, volatility in the credit markets may increase costs associated with debt instruments due to increased spreads over relevant interest rate benchmarks, or may affect our ability, or the ability of third parties we seek to do business with, to access those markets.
Continued volatility in equity markets, specifically including energy and commodity markets, may increase the costs associated with equity financings due to a low share price and may create the potential need for us to offer higher discounts and other value (e.g., warrants). There is no assurance that we will be successful in obtaining required financing as and when needed and on acceptable terms, if at all.
We have experienced negative cash flows from operations and may need additional financing in connection with the implementation of our business and strategic plans from time to time.
The Company has had negative cash flow from operations in prior years, and at low commodity prices a number of our mining properties will be on standby, making it less likely that the Company will be able to generate positive cash flows from operations in those circumstances. If the Company cannot generate positive cash flows from operations, its ability to fund its operations and implement its business plans may depend on its ability to obtain financing through joint ventures, debt financing, equity financing or other means. There can be no assurance that we will be able to achieve and maintain positive cash flow from operations to fund our financing needs. Further, if cash flows from operations are negative, there is no assurance that the Company will be able to raise additional funds, if needed, or that if any such additional funds are
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raised, that the Company will be able to raise such funds on commercially attractive terms. If we do not achieve positive cash flows or are unable to raise additional funds when needed, we may not be able to continue to fund our operations.
Servicing our debt requires a significant amount of cash, and we may not have sufficient cash flow from our business operations to pay our debt.
Our indebtedness as of December 31, 2025 was $110.0 million, which includes our Convertible Senior Notes. Our ability to make scheduled payments of the principal of, to pay interest on, or to refinance our indebtedness, including our Convertible Senior Notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. In addition, holders of the Convertible Senior Notes will have the right to require us to repurchase their notes for cash upon the occurrence of certain fundamental changes. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, restructuring debt, incurring more debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations or negatively affect our liquidity position.
Our corporate strategy includes acquisitions of mining assets and businesses. Such acquisitions are subject to risks and we may not realize the anticipated benefits of an acquisition, which could impair our results of operations, financial condition, cash flows and liquidity.
enCore has completed a number of transactions over the last several years and from time to time may evaluate opportunities to acquire uranium mining assets and businesses. Despite the Company’s belief that these transactions were, and others which may be completed in the future will be, in the Company’s best interest and benefit the Company and its shareholders, the Company may not realize the anticipated benefits of such transactions or realize the full value of the consideration paid or received to complete the transactions. In addition, acquisitions may be significant in size, may change the scale of enCore’s business and may expose it to new geographic, political, operating, financial and geological risks. enCore’s success in its acquisition activities depends on its ability to identify suitable acquisition candidates, acquire them on acceptable terms and integrate their operations successfully with those of enCore. Any acquisitions would be accompanied by risks, such as the difficulty of assimilating the operations and personnel of any acquired companies; the potential disruption of enCore’s ongoing business; the inability of management to maximize the financial and strategic position of enCore through the successful incorporation of acquired assets and businesses; additional expenses associated with amortization of acquired intangible assets; the maintenance of uniform standards, controls, procedures and policies; the impairment of relationships with employees, customers and contractors as a result of any integration of new management personnel; dilution of enCore’s present shareholders or of its interest in its subsidiaries as a result of the issuance of equity to pay for acquisitions; and the potential unknown liabilities associated with acquired assets and businesses. There can be no assurance that enCore would be successful in overcoming these risks or any other problems encountered in connection with such acquisitions, which could result in accounting impairments, write-downs of the carrying values of mineral properties or other assets and could accordingly have a material adverse effect on its business, results of operations, financial condition, cash flows and liquidity.
There is no right for our shareholders to evaluate the merits or risks of any future acquisition undertaken by enCore except as required by applicable laws and regulations.
Our properties do not contain Mineral Reserves under S-K 1300, and some of the Company’s properties, projects and facilities may not be economic at any point in time or at all.
None of our properties currently contain any known Mineral Reserves. Some or all of our properties, projects and facilities may not be economic for uranium extraction, recovery or processing at any point in time. Generally, we intend to continue to hold, and in certain cases advance, properties, projects and facilities which may not be economic at any point in time in anticipation of possible future increases in the prices of uranium, as the case may be. However, in those circumstances, there can be no assurance at any time that such prices will ever, or within a reasonable time period, increase to the levels required to advance those properties or, in the case of projects or facilities on standby, to resume exploration, extraction, recovery or processing activities at those projects or facilities. In the event of depressed commodity prices, we may continue to hold our standby properties, projects and facilities because we believe that prices may be likely to rise to such levels within a reasonable time period to justify future production. This ability to maintain scalability as commodity prices increase is a key component of our business strategy. However, as there is a cost associated with holding and, in some cases, maintaining such properties, projects and facilities on standby during periods of depressed commodity prices, in
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those circumstances we continuously evaluate, on a case-by-case basis, such costs against the prospects for price increases, and may from time to time sell, drop or reclaim any such properties, projects or facilities.
Mining on properties having no known Mineral Resources or Mineral Reserves is inherently speculative and may not prove to be economic at any point in time or at all.
Mining is an inherently speculative business. Some of the properties on which we have the right to mine are not known to have any Mineral Reserves or Mineral Resources. There is a possibility that we will not discover uranium on any or all of our properties which can be mined or extracted at a profit at any point in time or at all. Even if we do discover and mine such minerals, the deposits may not be of the quality or size necessary for us or a potential purchaser of the property to make a profit from mining it. Few properties that are explored are ultimately developed into producing mines, and mines that are developed may not be profitable. Unusual or unexpected geological formations, geological formation pressures, fires, power outages, labor disruptions, flooding, explosions, cave-ins, landslides and the inability to obtain suitable or adequate machinery, equipment or labor, as well as all necessary licenses and permits, are just some of the many risks involved in mineral exploration programs and their subsequent development. However, we may elect, now or in the future, to proceed with the extraction of minerals on one or more of those projects without having completed the technical work required to declare a Mineral Reserve. If we are then unable to extract uranium in commercially viable quantities, the capital investment of mining such properties may be lost and could materially impact our business.
We may not realize any or all of the anticipated benefits from the Alta Mesa Project.
As part of our business strategy, we expect to see certain near-term benefits, including a licensed uranium extraction facility with licensed and permitted Mineral Resources that will add to our overall extraction capacity in South Texas, as well as longer-term opportunities for growth from a large contiguous mineral property that has significant identified Mineral Resources and the potential for additional Mineral Resources that could be discovered on that property. Any benefits and growth that we realize from such efforts may differ materially from our estimates. In particular, our estimates of the potential benefits and growth from the acquisition of the Alta Mesa Project are based in part on a valuation of the Alta Mesa Project that may differ from the performance of the Alta Mesa Project on a going-forward basis. Achieving the benefits of the acquisition of the Alta Mesa Project will depend, in part, on our ability to integrate operations of the Alta Mesa Project successfully and efficiently with our business. The challenges involved in this integration, which may be complex and time-consuming, include the following:

| ● | the diversion of management attention from other important business objectives;

| ● | the ability to locate, hire and retain experienced staff to construct wellfields and safely conduct operations;

| ● | the ability to locate, hire and retain experienced contractors to allow efficient delineation drilling and well installation at a necessary rate to meet production needs; and

| ● | the Company’s ongoing relations with Boss with respect to the joint venture in the Alta Mesa Project.

In addition, any benefits that we realize may be offset, in whole or in part, by reductions in revenues, or through increases in other expenses, including costs to achieve our estimated synergies and growth. Our plans for the Alta Mesa Project are subject to numerous risks and uncertainties that may change at any time. We cannot assure you that our initiatives will be completed as anticipated or that the benefits we expect will be achieved on a timely basis or at all. It may take longer than expected to achieve the anticipated benefits and growth and there is no guarantee that the Alta Mesa Project will maintain extraction levels. If the Alta Mesa Project does not achieve the anticipated benefits and growth or maintain extraction levels, this may adversely affect the future financial results of the Company.
We depend on key personnel, and our success will depend on our continued ability to retain and attract such qualified personnel.
enCore is dependent on the services of key management personnel. The loss of any of these key personnel, if not replaced, could have a material adverse effect on enCore’s business and operations. enCore does not currently have key-person insurance on these individuals.
Timely availability and training, strong retention rates of staffing and timely retention of contractors cannot be assured in our industry, many aspects of which are highly specialized. This is particularly true in the current labor markets in which we recruit our employees and contractors, including where we compete with higher paying energy jobs, and because of the remote locations for which employees and contractors are needed. The skilled professionals with expertise in geologic,
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engineering and process aspects of uranium ISR, radiation safety and other facets of our business are currently in high demand, as there are relatively few professionals with both expertise and experience.
Certain directors and officers may be subject to conflicts of interest with respect to the Company due to their relationship with other resource companies.
enCore’s directors and officers may serve as directors or officers of other resource companies or have significant shareholdings in other resource companies and, to the extent that such other companies may participate in ventures in which enCore may participate, the directors and officers of enCore may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of enCore’s directors, a director who has such a conflict will abstain from voting for or against the approval of such participation or such terms in accordance with the BCBCA. From time to time several companies may participate in the acquisition, exploration and development of natural resource properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment. In accordance with the laws of British Columbia, the directors of enCore are required to act honestly, in good faith and in the best interests of enCore. Interests of directors and officers in a particular program or other resource company may conflict with the interest of our shareholders in earning income on their investment in our common shares.
Fluctuations in the fair value of our marketable equity securities could materially affect our results of operations, financial condition, and cash flows.
We hold investments in publicly traded equity securities that are measured at fair value, with changes in fair value recognized in earnings. The market prices of these securities are subject to volatility due to factors beyond our control, including fluctuations in the broader equity markets, changes in investor sentiment, macroeconomic conditions, interest rates, foreign exchange rates, industry specific developments, and company specific events affecting the issuers of such securities. As a result, the fair value of our marketable securities may decline significantly over short periods of time.
Unrealized losses resulting from declines in the market value of our equity securities are recorded in our results of operations and could adversely affect our reported earnings, even if we do not intend to sell the underlying securities and the issuers’ long-term fundamentals remain unchanged. In addition, if we determine that it is appropriate to divest any of these investments during periods of market weakness, we may be required to realize losses that could negatively impact our liquidity and financial condition. Accordingly, volatility in the fair value of our marketable securities could cause significant variability in our financial results from period to period.
Risks related to our Industry
There are risks associated with the exploration of, development of, and extraction from mineral properties.
The business of exploration for minerals involves a high degree of risk. Few properties that are explored are ultimately developed into producing mines. There is no assurance that the exploration programs on enCore’s current or future mineral properties will result in the discovery of new resources or lead to the development of a commercially viable orebody.
Development of any of enCore’s properties are subject to numerous risks, including, but not limited to, delays in obtaining equipment, material and services essential to developing the projects in a timely manner; changes in environmental or other government regulations; currency exchange rates; labor shortages; and fluctuation in metal prices. Furthermore, the economic feasibility of developing a mineral project is based on many factors such as estimation of mineral reserves, tonnage and grade, anticipated metallurgical recoveries, environmental considerations and permitting, future metal prices and anticipated capital and operating costs of these projects, and it is possible that actual capital and operating costs and economic returns will differ significantly from those estimated for a project prior to extraction.
enCore’s mineral properties have no operating history upon which estimates of future projection and cash operating costs can be based. Estimates of mineral resources, proven and probable mineral reserves and cash operating costs are, to a large extent, based upon the interpretation of geologic data obtained from drill holes and other sampling techniques. The results of feasibility studies that derive estimates of capital and operating costs based upon the quantity, grade and configuration of mineral reserves as well as the expected recovery rates of metals from the mineralized material, are subject to change. As a result, it is possible that actual capital and operating costs and economic returns will differ significantly from those currently estimated for a project prior to development or operation. The remoteness and restrictions on access of certain of the properties in which enCore has an interest could have an adverse effect on profitability in that infrastructure costs would be higher. There are also physical risks to the exploration personnel working in the rugged terrain, often in poor
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climate conditions, which can be abated through safety training, adherence to high safety standards and the use of modern communication technologies.
With all mineral operations there is uncertainty and, therefore, risk associated with operating parameters and costs resulting from the scaling up of extraction methods tested in laboratory conditions. Development of a mineral property does not assure a profit on the investment or recovery of costs. In addition, extraction hazards or environmental damage could greatly increase the cost of operations, and various operating conditions may adversely affect the extraction from mineral properties. These conditions include delays in obtaining governmental approvals or consents, insufficient transportation capacity or other geological, geotechnical and mechanical conditions. While diligent supervision and effective maintenance operations can contribute to maximizing extraction rates over time, extraction delays from normal operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.
The nature of our use of independent contractors to conduct drilling rig operations presents inherent risks of loss, including weather-related risks, that could adversely affect our results of operations.
Our business relies on the use of independent drilling rig contractors, and their operations are subject to many hazards inherent in the drilling industry, including environmental pollution, blowouts, cratering, explosions, fires, loss of well control, loss of or damage to the wellbore or underground reservoir, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental and natural resources damage, reputational harm and damage to the property of others.
Accidents may occur, we may be unable to obtain desired contractual indemnities, and our insurance may prove inadequate in certain cases. The occurrence of an event for which we are not sufficiently insured or indemnified, or the failure or inability of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses that could adversely affect our business, financial condition and liquidity. In addition, insurance may not be available to cover certain risks, including war and political risks. Even if available, insurance may be inadequate or insurance premiums or other costs may increase significantly in the future, making insurance prohibitively expensive.
We expect to continue facing upward pressure in our insurance renewals, our premiums and deductibles may be higher, and some insurance coverage may either be unavailable or more expensive than it has been in the past. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention. We may choose to increase the levels of deductibles (and thus assume a greater degree of risk) from time to time in order to minimize our overall costs, which could exacerbate the effect of our losses on our financial condition and liquidity. In addition, our safety record is a competitive advantage for us and if one or more incidents were to occur it could significantly affect this advantage.
We are subject to the risks and hazards normally encountered by companies in the mineral exploration and extraction industry.
enCore’s business is subject to a number of risks and hazards, including environmental hazards; industrial accidents; labor disputes; catastrophic accidents; fires; blockades or other acts of social activism; changes in the regulatory environment; impact of non-compliance with laws and regulations or the implementation of new laws and regulations; natural phenomena, such as inclement weather conditions, underground floods, earthquakes, pit wall failures, ground movements, tailings pipeline and dam failures and cave-ins; and encountering unusual or unexpected geological conditions and technological failure of mining methods.
In addition, success in exploration is dependent on a number of factors including the quality of management, quality and availability of geological expertise and the availability of exploration capital. Major expenses may be required to establish reserves by drilling, constructing mining or processing facilities at a site, developing metallurgical processes and extracting uranium from ore.
There is no assurance that the foregoing risks and hazards will not occur or will not result in damage to, or destruction of, the properties and assets of enCore, personal injury or death, environmental damage, delays in or interruption of or cessation of extraction from the properties or impairment of enCore’s exploration or development activities or in unsuccessful exploration, which could result in unforeseen costs, monetary losses and potential legal liability and adverse governmental action, all of which could have an adverse impact on enCore’s future cash flows, earnings, results of operations and financial condition.
The Company risks potential for obsolescence, unexpected maintenance costs, dependence on the lessor's financial stability, potential for damage or loss of equipment, and not having full control over asset usage due to lease terms.
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The Company owns three drilling rigs that it will lease to its existing independent contractors to provide the ability for them to capitalize additional drilling capacity and support the Company’s exploration drilling program. There is a risk that the leased equipment could become outdated quickly, leaving us with technology that is no longer suitable for our needs. Drilling rigs are known to carry high maintenance costs, and while leases may include some maintenance, unforeseen repairs or significant maintenance needs could result in additional costs not factored into the lease agreement. As a lessor, we do not control the equipment while it is operated by the lessee, and there could be a serious incident such as a fatality, serious injury, or serious damage to our leased equipment.
Economic extraction of minerals from uranium deposits may not be commercially viable.
Whether a uranium deposit will be commercially viable depends on a number of factors, including the particular attributes of a deposit, such as its size and grade; costs and efficiency of the recovery methods than can be employed; proximity to infrastructure; financing costs; and governmental regulations, including regulations relating to prices, taxes, royalties, infrastructure, land use, worker health and safety, importing and exporting of commodities and environmental protection. The effect of these factors, either alone or in combination, cannot be accurately predicted and their impact may result in enCore not being able to economically extract minerals from any identified mineral resource.
Estimation of Mineral Resources is subjective and uncertain.
The figures presented for Mineral Resources in this Annual Report are only estimates. The estimating of Mineral Resources is a subjective process and the accuracy of Mineral Resource estimates is a function of the quantity and quality of available data, the accuracy of statistical computations, and the assumptions used and judgments made in interpreting available engineering and geological information.
There are numerous uncertainties inherent in estimating quantities of Mineral Resources, including many factors beyond our control, and no assurance can be given that the recovery of Mineral Resources, or even estimated Mineral Reserves, will be realized. In general, estimates of mineral resources are based upon several factors and assumptions made as of the date on which the estimates were determined, including (i) geological and engineering estimates that have inherent uncertainties and the assumed effects of regulation by governmental agencies; (ii) the judgment of the geologists, engineers and other professionals preparing the estimate; (iii) estimates of future uranium prices and operating costs; (iv) the quality and quantity of available data and the interpretation of that data; and (v) the accuracy of various mandated economic assumptions, all of which may vary considerably from actual results.
All estimates are, to some degree, uncertain; with ISR, this is due in part to limited sampling information collected prior to mining. For these reasons, estimates of the recoverable Mineral Resources prepared by different professionals or by the same professionals at different times, may vary substantially. As such, there is significant uncertainty in any Mineral Resource estimate and actual deposits encountered and the economic viability of a deposit may differ materially from our estimates.
Estimated Mineral Resources may have to be re-estimated based on changes in uranium prices, further exploration or development activity or actual production experience. This could materially and adversely affect estimates of the volume or grade of mineralization, estimated recovery rates or other important factors that influence Mineral Resource estimates. Mineral Resources are not Mineral Reserves and there is no assurance that any resource estimate will ultimately be reclassified as proven or probable reserves. Mineral Resources which are not Mineral Reserves do not have demonstrated economic viability. There is significant uncertainty in any Mineral Resource estimate and the actual deposits encountered and the economic viability of a deposit may differ materially from enCore’s estimates.
No assurances can be given that future mineral production estimates will be achieved.
Estimates of future production for enCore’s mining operations as a whole are derived from enCore’s mining plans. These estimates are subject to change. enCore cannot give any assurance that it will achieve its production estimates. enCore’s failure to achieve its production estimates could have a material and adverse effect on any or all of enCore’s future cash flows, results of operation, financial condition and prospects. The plans are developed based on, among other things, mining experience, reserve estimates, assumptions regarding ground conditions and physical characteristics or ores (such as hardness and presence or absence of certain metallurgical characteristics) and estimated rates and costs of production. Actual production may vary from estimates for a variety of reasons, including risks and hazards of the types discussed above, and as set out below, including:
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| ● | actual ore mined varying from estimates in grade, tonnage, and metallurgical and other characteristics;

| ● | mining dilution;

| ● | ventilation and adverse temperature levels underground;

| ● | accidents;

| ● | equipment failures;

| ● | natural phenomena such as inclement weather conditions, floods, blizzards, droughts, rockslides and earthquakes;

| ● | encountering unusual or unexpected geological conditions;

| ● | changes in power costs and potential power shortages;

| ● | shortages of principal supplies needed for operation, including explosives fuels, chemical reagents, water, equipment parts and lubricants;

| ● | strikes and other actions by labor at unionized locations; and

| ● | regulatory restrictions imposed by government agencies.

Such occurrences could, in addition to stopping or delaying mineral extraction, result in damage to mineral properties, injury or death to persons, damage to enCore’s property or the property of others, monetary losses and legal liabilities. These factors may also cause a mineral deposit that has been mined profitably in the past to become unprofitable. Estimates of production from properties not yet in production or from operations that are to be expanded are based on similar factors (including, in some instances, feasibility studies prepared by enCore’s personnel and outside consultants) but it is possible that actual operating costs and economic returns will differ significantly from those currently estimated. It is not unusual in new mining operations to experience unexpected problems during the start-up phase. Delays often can occur in the commencement of production. The occurrence of any of the foregoing could have an adverse impact on enCore’s future cash flow, earnings, results of operations and financial condition.
Our business relies on the use of drilling rigs operated by independent contractors to conduct exploration activities, and as such, their operating expense includes fixed costs that may not decline in proportion to decreases in rig utilization and day rates.
Independent contractors operate drilling rigs owned or leased by the Company to conduct exploration activities on our mineral properties. Their operating expense includes all direct and indirect costs associated with the operation, maintenance and support of our drilling and related equipment, many of which are not affected by changes in day rates and some of which are not affected by utilization. During periods of reduced revenues or activity, certain of their fixed costs (such as depreciation) may not decline and often they may incur additional costs. During times of reduced utilization, reductions in costs may not be immediate as they may not be able to fully reduce the cost of their support operations in a particular geographic region due to the need to support the remaining drilling rigs in that region. Accordingly, a decline in revenues due to lower day rates or utilization may not be offset by a corresponding decrease in drilling services and solutions expense, which could have a material adverse effect on their ability to conduct drilling operations on our behalf which could have a material adverse effect on our business, financial condition and results of operations.
Shortages of drilling contractors, drilling supplies or other key materials could adversely affect our operations.
The drilling services and solutions business is highly cyclical. During periods of increased demand for drilling services and solutions and periods of supply chain disruption, delays in availability and shortages of drilling contractors and drilling supplies can occur, and it can impact our ability to execute our exploration activities according to our business plans. Additionally, suppliers may seek to increase prices for equipment, supplies, and services, which we are unable to pass through to our customers. Further, certain key rig components, parts and equipment are also either purchased from, fabricated or serviced by a limited number of vendors, which, in some cases, may be thinly capitalized and disproportionately affected by any loss of business, downturn in the energy industry, supply chain disruptions, or reduction or availability of credit. The failure of one or more third-party suppliers, manufacturers or service providers to provide equipment, components, parts or services, whether due to capacity constraints, labor shortages or other labor-related difficulties, production or delivery disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment, is beyond our control and could materially disrupt our operations or result in the delay, renegotiation or cancellation of drilling contracts, thereby causing a loss of contract drilling backlog and/or revenues to us, as well as an increase in operating costs. If we are not able to effectively manage these disruptions and delays in the future, they could have a material adverse effect on our business, financial condition and results of operations.
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No assurance can be given that estimates of commodity prices used in preliminary economic assessments will actually be realized.
The estimates of uranium prices used in S-K 1300 technical reports are based on conditions prevailing at the time of the writing of such reports. Conditions can change significantly over relatively short periods of time and, as such, there can be no assurance that the estimates of the price of uranium used in the S-K 1300 technical reports will actually be realized. Changes in the uranium price could have a significant impact on the viability of enCore’s mineral projects and an adverse impact on enCore’s future cash flows, earnings, results of operations and financial condition.
Projects may not advance or achieve production if key permits are not obtained or retained.
The advancement of mineral properties through exploration to commercial operation normally requires securing and maintaining key permits and/or licenses (collectively, the “permits”) from regulatory or governmental authorities. While enCore puts its reasonable best efforts into securing the permits necessary to advance its properties according to the policies and guidelines applicable to each permit, approval of permits rests solely with the governing agency and is outside of enCore’s control. In addition to the statutory and regulatory processes, there are other intangible factors, such as limited agency staffing due to budgetary constraints and staff turnover and government shutdowns that can impact permit reviews and approvals.
The requirements for obtaining a RML for the Company’s mineral properties in the United States allows for public participation. Third parties may object to the issuance of RMLs and/or permits required by the Company, which may significantly delay the Company’s ability to obtain an RML and/or permit. Also, insufficient or insufficiently trained staff at regulatory agencies or government shutdowns may delay the issuance of required permits. Generally, public objections can be overcome through the procedures set forth in the applicable permitting legislation; however, significant financial resources and managerial resources are required through this process. In addition, the various regulatory agencies must allow and fully consider the public objections/comments according to such procedures set out in the applicable legislation and there can be no assurance that the Company will be successful in obtaining an RML and/or permit, which could have a material adverse effect on the viability of a project.
Finalization of the state permitting process for the Dewey Burdock Project is subject to hearings with public participation. If the state permits are not issued in a timely manner, or at all, it could have a material adverse impact on the Company’s financial performance, cash flows and results of operations. In addition, the Company will have to assess whether an impairment allowance is necessary, which, if required, could be material. There can be no guarantee that enCore will succeed in obtaining the permits necessary to advance its projects, and a failure to obtain necessary permits or retain permits that have been granted may result in an inability to realize any benefit from its exploration or development activities on its properties.
Native American tribes may be involved in the permitting process, which could cause delays or increased expenses.
None of the Company’s mineral properties are located within the boundaries of Native American lands or other property interests that are controlled or owned by Native Americans under the jurisdiction of the United States federal government. However, under federal legislation, historic cultural properties of religious significance that can be identified are to be avoided or activities are to be mitigated such that the essential nature of the properties is not lost to a culture. Throughout the western United States, Native American tribes have had historical relationships with properties that are now owned by private parties, the federal government or state governments. In any federal permitting action on these properties, the agency involved is required to make an effort to communicate with Native American tribes to determine any areas of traditional cultural significance, which involves “government to government” discussions with the potentially affected Native American tribes; therefore, delays in permitting may occur through this process. In the event that traditional cultural properties are identified within a project area, the Company and the agency must determine the best method of development to ensure that disturbances are minimized or mitigated, which could be costly and have an adverse impact on enCore’s future cash flows, earnings, results of operations and financial condition.
Opposition to mining may disrupt our business activities.
In recent years, governmental agencies, non-governmental organizations, individuals, communities and courts have become more vocal and active with respect to their opposition to certain mining and business activities, including with respect to production and uranium recovery at our facilities. This opposition may take on forms such as road blockades, vandalism, threats and/or slander, applications for injunctions seeking to cease certain construction, development, extraction, mining and/or milling or recovery activities, refusals to grant access to lands or to sell lands on commercially viable terms,
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lawsuits for damages or to revoke or modify licenses and permits, issuances of unfavorable laws and regulations, changes in regulatory attitudes and interpretations and other rulings contrary to or otherwise harming our interests. These actions can occur in response to current activities or in respect of mines or facilities that are decades old. In addition, these actions can occur in response to our activities or the activities of other unrelated entities. Opposition to our activities may also result from general opposition to nuclear energy and mining. Opposition to our business activities are beyond our control. Any opposition to our business activities may cause a disruption to our business activities and may result in increased costs and delays, which could have a material adverse effect on our business and financial condition.
Permits received are subject to expiration and we may not be able to obtain, maintain or amend rights, authorizations, licenses, permits or consents required for our operations.
Our exploration and mining activities are dependent upon the grant of appropriate rights, authorizations, licenses, permits and consents, as well as continuation and amendment of these rights, authorizations, licenses, permits and consents already granted, which may be granted for a defined period of time, or may not be granted or may be withdrawn or made subject to limitations. There can be no assurance that all necessary rights, authorizations, licenses, permits and consents will be granted to us, or that authorizations, licenses, permits and consents already granted will not be withdrawn or made subject to limitations.
Permits granted by the jurisdictions in which enCore operates are typically issued with an expiry date requiring enCore to undertake certain activities within a given time frame in order for the permit to remain valid. While enCore makes every reasonable attempt to satisfy the terms and conditions of the permits it is granted, there can be no assurance that unforeseen circumstances may prevent the Company from doing so, and permits received may expire, which could have an adverse impact on enCore’s future cash flows, earnings, results of operations and financial condition.
The title to our mineral property interests may be challenged.
enCore has investigated its rights to explore and extract minerals from all of its material properties and, to the best of its knowledge, those rights are in good standing. No assurance can be given, however, that enCore will be able to secure the grant or the renewal of existing mineral rights and tenures on terms satisfactory to it, or that governments in the jurisdictions in which enCore operates will not revoke or significantly alter such rights or tenures or that such rights or tenures will not be challenged or impugned by third parties, including local governments, aboriginal peoples or other claimants. Although enCore is not currently aware of any existing title uncertainties with respect to any of its material properties, there is no assurance that such uncertainties will not result in future losses or additional expenditures, which could have an adverse impact on enCore’s future cash flows, earnings, results of operations and financial condition.
The procurement of mining interests and retaining skilled employees is highly competitive.
The Company competes with other energy companies and individuals for capital, mining interests on exploration properties and undeveloped lands, acquisitions of Mineral Resources and reserves and other mining assets. The Company also competes with other energy companies to attract and retain key executives and employees. There can be no assurance that the Company will continue to be able to compete successfully with its competitors in acquiring such properties and assets or in attracting and retaining skilled and experienced employees. The energy industry has been impacted by increased worldwide demand for critical resources such as input commodities, drilling equipment, and skilled labor, and these shortages have caused unanticipated cost increases and delays in delivery times, thereby impacting operating costs, capital expenditures and extraction schedules.
The Company may be at a competitive disadvantage due to the fact that many of the Company’s competitors have greater financial resources to source mineral properties and attract and retain key executives and employees. Accordingly, there can be no assurance that the Company will be able to compete successfully.
The uranium industry is highly competitive, and we may not be successful in acquiring additional contracts and projects.
The national and international uranium industry is highly competitive. enCore intends to market uranium to utilities in direct competition with supplies available from a relatively small number of mining companies, from excess inventories, including inventories made available from the decommissioning of nuclear weapons, from reprocessed uranium and plutonium derived from used reactor fuel and from the use of excess enrichment capacity to re-enrich depleted uranium tails. Our competition includes larger, more established companies with longer operating histories that not only explore for and produce uranium but also market uranium and other products on a regional, national or worldwide basis. Any failure in
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the expected level of demand for our uranium to materialize as a result of competition could have a material adverse effect on the Company’s business, results of operations, financial condition, cash flow and liquidity.
Nuclear energy competes with other sources of energy and is subject to public acceptance of nuclear energy as a means of generating electricity.
Nuclear energy competes with other sources of energy, including oil, natural gas, coal and hydroelectricity. These other energy sources are to some extent interchangeable with nuclear energy, particularly over the longer term. Sustained lower prices of oil, natural gas, coal and hydro-electricity may result in lower demand for uranium concentrates, which could have a material adverse effect on our business, results of operations, financial condition, cash flows and liquidity. Technical advances in, and government support and subsidies for, renewable energy sources could make these forms of energy more viable and have a greater impact on nuclear fuel demands.
Furthermore, growth of the uranium and nuclear power industry will depend upon continued and increased acceptance of nuclear technology as a means of generating electricity. Because of unique political, technological and environmental factors that affect the nuclear industry, the industry is subject to public opinion risks which could have an adverse impact on the demand for nuclear power and increase the regulation of the nuclear power industry. The nuclear incident that occurred in Japan in March 2011 had significant and adverse effects on both the nuclear and uranium industries. If another nuclear incident were to occur, it could impact the continuing acceptance of nuclear energy and the future prospects for nuclear power generation, including causing governments of certain countries to further increase regulation for the nuclear industry, reduce or abandon current reliance on nuclear power or reduce or abandon existing plans for nuclear power expansion. Any of the foregoing has the potential to reduce current and/or future demand for nuclear power, resulting in lower demand for uranium and lower market prices for uranium, which could have a material adverse effect on enCore’s business, results of operations, financial condition, cash flows and liquidity.
The Company’s operations are sensitive to the market price of uranium, which may be volatile.
enCore’s future revenues will be directly related to the prices of uranium as its revenues will be derived from uranium mining. The Company’s financial condition, results of operations, earnings and operating cash flows will be significantly affected by the market price of uranium, which is cyclical and subject to substantial short and long-term price fluctuations. Among other factors, uranium prices also affect the value of the Company’s resources, as well as the market price of its common shares.
Uranium prices are and will continue to be affected by numerous factors beyond enCore’s control. Such factors include, among others, the demand for nuclear power; political and economic conditions in uranium producing and consuming countries such as Canada, the United States, Russia and other former Soviet republics; reprocessing of used reactor fuel and the re-enrichment of depleted uranium tails; sales of excess civilian and military inventories (including from the dismantling of nuclear weapons) by governments and industry participants; and production levels and costs of production in countries such as Russia and former Soviet republics, Australia and countries in Africa; international wars or conflicts (including Russia’s military invasion of Ukraine and the war in Iran); geopolitical developments (including trading and tariff arrangements, sanctions and cybersecurity attacks), terrorism, natural disasters and public health epidemics or pandemics. The extent and duration of such events and resulting market disruptions cannot be predicted but could be substantial and could magnify the impact of other risks to the Company. These and other similar events could adversely affect the United States and foreign financial markets and lead to increased market volatility.
If, after the commencement of commercial production, the uranium price falls below the costs of extraction at enCore’s mines for a sustained period, it may not be economically feasible to continue extraction at such sites. This would materially and adversely affect production, extraction and enCore’s results of operation and financial position. A decline in the uranium price may also require enCore to write down its Mineral Resources, which would have a material adverse effect on its earnings and profitability.
Changing global and regional political and economic conditions could adversely impact our business.
Recent political and economic shifts, both domestic and international, may create uncertainty and pose risks to our operations and business. Government policies related to protectionism, economic nationalism and attitudes toward multinational corporations could result in regulatory changes, trade barriers or investment restrictions. Additionally, international trade disputes, including tariffs, counter tariffs, export controls, sanctions and currency regulations, may increase costs, further disrupt supply chains, and have other negative impacts on our business and operating models. Furthermore, market volatility, driven by shifts in U.S. and foreign trade policies, fluctuating interest rates or currency controls may affect commodity prices, capital availability and investor confidence. Even the perception of these risks could lead to reduced investment, higher production and operating costs, and other operational challenges. If such trends
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continue, they may have a material adverse effect on our business and financial performance; it is difficult to estimate the impact on our business.
Hedging activities may not be successful.
enCore does not hedge any of its future uranium extraction but may engage in hedging activities in the future. Hedging activities would be intended to protect enCore from the fluctuations of the price of uranium and to minimize the effect of declines in the uranium price on results of operations for a period of time. Although hedging activities may protect enCore against lower uranium prices, they may also limit the price that can be realized on uranium that is subject to forward sales and call options where the market price of uranium exceeds the uranium price in a forward sale or call option contract.
We may need additional financing in connection with the implementation of our business and strategic plans from time to time.
The exploration, construction, development and acquisition of mineral properties and the ongoing operation of mines and other facilities requires a substantial amount of capital and may depend on our ability to obtain financing through joint ventures, debt financing, equity financing or other means. We may accordingly need further capital in order to take advantage of further opportunities or acquisitions. Our financial condition, general market conditions, volatile uranium market, volatile interest rates, legal claims against us, a significant disruption to our business or operations, or other factors may make it difficult to secure financing necessary for the expansion of mining activities or to take advantage of opportunities for acquisitions. Further, volatility in the credit markets may increase costs associated with debt instruments due to increased spreads over relevant interest rate benchmarks, or may affect our ability, or the ability of third parties we seek to do business with, to access those markets.
Continued volatility in equity markets, specifically including energy and commodity markets, may increase the costs associated with equity financings due to a low share price and may create the potential need for us to offer higher discounts and other value. There is no assurance that we will be successful in obtaining required financing as and when needed on acceptable terms, if at all.
We currently are subject to, and in the future may be subject to, litigation, disputes or regulatory inquiries for a variety of claims, which could adversely affect our results of operations, harm our reputation or otherwise negatively affect our business.
From time to time, we may be involved in litigation, disputes or regulatory inquiries that arise in the ordinary course of business. These may include claims, lawsuits and proceedings involving labor and employment, wage and hour, commercial, alleged securities law violations or other investor claims, and other matters. For example, we currently are involved in a federal securities class action litigation, as described further in [Note 10 - Commitments and Contingencies]. Although we intend to defend against the claims vigorously and carry directors’ and officers’ liability insurance coverage, it is possible that our insurance may not cover all potential claims to which we are exposed and/or may not be adequate to fully cover liability that may be imposed as a result of such claims. Any claims against us, whether meritorious or not, could be time consuming, result in costly litigation, require significant amounts of management time, adversely affect our reputation and/or result in the diversion of significant operational resources. Because litigation is inherently unpredictable, we cannot ensure that such actions, including the federal securities class action litigation, will not have a material adverse effect on our revenue, business, brand, results of operations and financial condition.
The uranium industry is subject to numerous stringent laws, regulations and standards, including environmental protection laws and regulations. If any changes occur that would make these laws, regulations and standards more stringent, it may require capital outlays in excess of those anticipated or cause substantial delays, which would have a material adverse effect on our operations.
The current and future mining operations and exploration and development activities of enCore, particularly uranium mining, are subject to laws and regulations at the federal, state and local level governing worker health and safety, employment standards, mine development, mine safety, exports, imports, taxes and royalties, waste disposal, toxic substances, land claims of indigenous peoples, protection and remediation of the environment, mine decommissioning and reclamation, transportation safety and emergency response and other matters. Each jurisdiction in which enCore has properties regulates mining activities. It is possible that future changes in applicable laws and regulations or changes in their enforcement or regulatory interpretation could result in changes in legal requirements or in the terms of existing permits, licenses and approvals applicable to enCore or its projects, which could have a material and adverse impact on enCore’s current mining operations or planned development projects.
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enCore is also subject to various reclamation and other bonding requirements under federal, state, provincial or local air, water quality and mine reclamation rules and permits. Although enCore makes provision for reclamation costs, there is no assurance that these provisions will be adequate to discharge its obligations for these costs. Environmental and employee health and safety laws and regulations have tended to become more stringent over time. Any changes in such laws or in the environmental conditions at enCore’s properties could have a material adverse effect on enCore’s financial condition, cash flow or results of operations.
Failure to comply with applicable environmental and health and safety laws can result in injunctions, damages, suspension or revocation of permits and the imposition of penalties. There can be no assurance that enCore has been or will be at all times in complete compliance with such laws, regulations and permits, or that the costs of complying with current and future environmental and health and safety laws and permits will not adversely affect enCore’s business, results of operations, financial condition or prospects.
Worldwide demand for uranium is directly tied to the demand for electricity produced by the nuclear power industry, which is also subject to extensive government regulation and policies, and any change in these regulations or policies may have a negative impact on enCore’s business or financial condition.
Mineral exploration and the development of mines and related facilities is contingent upon governmental approvals, licenses and permits which are complex and time consuming to obtain and which, depending on the location of the project, involve multiple governmental agencies. The receipt, duration, amendment or renewal of such approvals, licenses and permits are subject to many variables outside of enCore’s control, including inadequate agency staff experience, inability of governmental agencies to process licenses and permits in a timely manner, reduced agency staff capacity, potential legal challenges from various stakeholders such as environmental groups, non-governmental organizations, aboriginal groups or other claimants. The costs and delays associated with obtaining necessary approvals, licenses and permits and complying with these approvals, licenses and permits and applicable laws and regulations could stop or materially delay or restrict enCore from proceeding with the development of an exploration project or the operation or further development of a mine. Any failure to comply with applicable laws and regulations or approvals, licenses or permits, even if inadvertent, could result in interruption or closure of exploration, development or mining operations, or material fines, penalties or other liabilities.
Where required, obtaining necessary permits to conduct exploration or mining operations can be a complex and time consuming process, and there is no assurance that any necessary permits will be obtainable on acceptable terms, in a timely manner or at all.
Insurance may not be available to cover the gamut of risks associated with mineral exploration, development and mining.
The mining industry is subject to significant risks that could result in damage to or destruction of property and facilities, personal injury or death, environmental damage and pollution, delays in extraction, expropriation of assets and loss of title to mining claims. No assurance can be given that insurance to cover the risks to which enCore’s activities are subject will be available at all or at commercially reasonable premiums. enCore currently maintains insurance within ranges of coverage that it believes to be consistent with industry practice for companies of a similar stage of development. enCore carries liability insurance with respect to its mineral exploration operations which includes a form of environmental liability insurance. Because insurance against environmental risks (including liability for pollution) or other hazards resulting from exploration and development activities can be prohibitively expensive, enCore’s insurance coverage is limited. The payment of any such liabilities would reduce the funds available to enCore. If enCore is unable to fully fund the cost of remedying an environmental problem, it might be required to suspend operations or enter into costly interim compliance measures pending completion of a permanent remedy.
We rely on contractors and experts in our operations, which could subject the Company to liability that could adversely impact the Company’s operations and financial condition.
In various aspects of its operations, enCore relies on the services, expertise and recommendations of its service providers and their employees and contractors, whom often are engaged at significant expense to the Company. For example, the decision as to whether a property contains a commercial mineral deposit and should be brought into extraction will depend in large part upon the results of exploration programs and/or feasibility studies, and the recommendations of duly qualified third-party engineers and/or geologists. In addition, while enCore emphasizes the importance of conducting operations in a safe and sustainable manner, it cannot exert absolute control over the actions of these third parties when providing services to enCore or otherwise operating on enCore’s properties. Any material error, omission, act of negligence or act resulting in environmental pollution, accidents or spills, industrial and transportation accidents, work stoppages or other actions could adversely affect the Company’s operations and financial condition.
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Extraction, capital and operating cost estimates may be inaccurate.
We prepare estimates of annual and future extraction, the attendant extraction and operational costs and required working capital for such levels of extraction, but there is no assurance that we will achieve those estimates. These types of estimates are inherently uncertain and may change materially over time. Operational cost estimates are affected by changes in extraction levels and may be affected by continuing inflation and cost-of-goods due to supply chain issues as well as the possible need to utilize a greater level of contractor services if required staffing is unavailable or cannot timely be hired and trained. Availability and consistent pricing of materials necessary in the installation of wells, surface production equipment, associated infrastructure, chemicals for processing and, expendable materials related to operations, can be variable depending on economic conditions locally and worldwide and may force changes in operations and timing of resource extraction. In addition, we rely on certain contractors related to the installation of wells and technical services associated with that installation. Their availability or cost of service can change depending on other local market conditions and may therefore affect the installation and extraction rates of mining.
Increased exposure to foreign exchange rate fluctuations may adversely affect our costs, earnings and value of some of our assets, including our common shares.
The Company maintains its accounting records and reports its financial position and results in U.S. Dollars. In addition to its listing on Nasdaq, the Company’s common shares are listed for trading on the TSX-V and trades in Canadian Dollars. In addition, enCore may raise funds through equity issuances which could be priced in U.S. Dollars or Canadian Dollars. Fluctuations in the Canadian currency exchange rate relative to the U.S. currency could significantly impact the Company, including its financial results, operations or the trading value of its securities. The price of uranium is quoted in U.S. Dollars, and a decrease in value of the U.S. Dollar would result in a relative decrease in the valuation of uranium and the associated market value from a Canadian currency perspective.
We utilize novel mining methods for extraction at our properties, which may not yield anticipated results.
The Company focuses on the ISR mining method for extraction at its properties. We have completed technical studies with respect to the ground conditions and the mineral resources estimated to be contained on the Company’s Rosita, Dewey-Burdock, Gas Hills, Mesteña Grande and Alta Mesa ISR uranium projects, and such studies indicate that the projects are amenable to extraction by way of ISR; however, actual conditions could be materially different from those estimated based on the Company’s technical studies completed to-date. While industry best practices have been utilized in the development of its estimates, actual results from the application of the ISR mining method may differ significantly. The Company will need to complete substantial additional work to further advance and/or confirm its current estimates for the use of the ISR mining method on its properties. As a result, it is possible that current estimates may not be achieved on any of the Company’s mining properties, which could adversely affect the Company’s operations and financial condition.
We are subject to technical innovation and obsolescence.
Requirements for our products and services may be affected by: technological changes in nuclear reactors, enrichment and used uranium fuel reprocessing. These technological changes could reduce the demand for our products and services and/or increase the supply of competitive products and services. The cost competitiveness of our operations may be impacted through the development and commercialization of other mining, milling, processing and other technologies. As a result, our competitors may adopt technological advancements that give them an advantage over the Company or that reduce the demand for the Company’s products and services or make them obsolete.
Since there is no liquid public market for uranium, selling uranium may take extended periods of time and suitable purchasers may be difficult to find, which could have a material adverse effect on our financial condition.
There is no liquid public market for the sale of uranium. The uranium futures market on the Chicago Mercantile Exchange does not provide for physical delivery of uranium, only cash on settlement.
The Company may not be able to, once produced, sell uranium at a desired price level for a number of weeks or months. The pool of potential purchasers or sellers is limited, and each transaction may require the negotiation of specific provisions. Accordingly, a sale cycle may take several weeks or months to complete. If the Company determines to sell any physical uranium that it has produced, it may likewise experience difficulties in finding purchasers that are able to accept a material quantity of physical uranium.
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The Company may also intend to hold physical uranium for long-term investment. During this term, the value of the Company’s uranium holdings will fluctuate and accordingly, the Company will be subject to losses should it ultimately determine to sell the uranium at prices lower than the acquisition cost. In addition, the Company may incur income statement losses, should uranium prices decrease or foreign exchange rates fluctuate unfavorably in future financial periods. The Company may be required to sell a portion or all of the physical uranium accumulated to fund its operations should other forms of financing not be available to fund the Company’s capital requirements, which could result in losses and adversely affect the Company’s operations and financial condition.
The ability to sell and profit from the sale of any eventual acquired uranium or mineral extraction from a property will be subject to the prevailing conditions in the applicable marketplace at the time of sale. The demand for uranium and other minerals is subject to global economic activity and changing attitudes of consumers and other end-users’ demand. The inability to sell on a timely basis in sufficient quantities at favorable prices could have a material adverse effect on the Company.
Global demand for uranium is subject to government regulation and policies, including international trade restrictions.
The international nuclear fuel industry, including the supply of uranium concentrates, is relatively small compared to other minerals, and is generally highly competitive and heavily regulated.
Worldwide demand for uranium is directly tied to the demand for electricity produced by the nuclear power industry, which is also subject to extensive government regulation and policies. In addition, the international marketing of uranium is subject to governmental policies and certain trade restrictions. For example, the war in Ukraine has resulted in impacts to the nuclear fuel industries and uranium producers, through the imposition of sanctions and counter sanctions, which has an adverse effect on energy and economic markets, including the nuclear fuel industries because of the vast reliance by the United States and other nations on uranium products exported from Russia and Russian-controlled or influenced sources. In addition, the conflicts in the Middle East, and other geopolitical tensions, including between the United States and China, also make it difficult to assess and predict the impact to the economy, supply disruption, increased prices of materials, and cyber-security threats.
In general, trade agreements, governmental policies and/or trade restrictions are beyond the control of the Company and may affect the supply of uranium available for use in markets like the United States and Europe, which are currently the largest markets for uranium in the world. Similarly, trade restrictions or foreign policy have the potential to impact the ability to supply uranium to developing markets, such as China and India. If substantial changes are made to regulations affecting the global marketing and supply of uranium, the Company’s business, financial condition and results of operations may be materially adversely affected.
Possible amendments to the general mining law could make it more difficult or impossible for us to execute our business plan.
Members of the U.S. Congress have repeatedly introduced bills which would supplant or alter the provisions of the United States Mining Law of 1872, as amended (the “General Mining Law”). Such bills have proposed, among other things, to (i) either eliminate or greatly limit the right to a mineral patent; (ii) significantly alter the laws and regulations relating to uranium mineral development and recovery from unpatented and patented mining claims; (iii) impose a federal royalty on production from unpatented mining claims; (iv) impose time limits on the effectiveness of plans of operation that may not coincide with mine or facility life; (v) impose more stringent environmental compliance and reclamation requirements on activities on unpatented mining claims; (vi) establish a mechanism that would allow states, localities and Native American tribes to petition for the withdrawal of identified tracts of federal land from the operation of the U.S. General Mining Law; and (vii) allow for administrative determinations that mining or similar activities would not be allowed in situations where undue degradation of the federal lands in question could not be prevented. If enacted, such legislation could change the cost of holding unpatented mining claims and could significantly impact our ability to develop locatable Mineral Resources on our patented and unpatented mining claims. Although it is impossible to predict at this point what any legislated royalties might be, enactment could adversely affect the potential for construction and development and the economics of existing operating mines and facilities. Passage of such legislation could adversely affect our financial performance.
Our operations on U.S. federal lands may be impacted by mineral withdrawals or the designation of national monuments by the U.S. President or government, either of which could have significant impacts on the Company and our operations, as well as by other factors.
Mining claims on U.S. federal lands are subject to mineral withdrawals by the federal government or the designation of national monuments by the U.S. President under the Antiquities Act of 1906. In both cases, the withdrawal or the
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designation of a national monument withdraws the area from location and entry under the General Mining Law, subject to valid existing rights. What this means is that no new mining claims may be filed on the withdrawn or designated lands and no new plans of operations may be approved, other than plans of operations on mining claims that were valid at the time of withdrawal or designation and that remain valid at the time of plan approval. Whether or not a mining claim is valid must be determined by a mineral examination conducted by the BLM. The mineral examination, which involves an economic evaluation of a project, must demonstrate the existence of a locatable mineral resource and that the mineral resource constitutes discovery of a valuable mineral deposit. Any future withdrawal of mineral lands from location and entry or future designation of additional national monuments has the potential to prevent further development on exploration stage claims held by the Company in the affected area as well as the potential for the Company to lose the ability to continue to develop mining operations on other claims in the affected area if a mineral examination indicates the deposit is uneconomical and that the claim is not valid, either of which could have significant impacts on the Company.
The risks of exchanges of state-owned lands in mineral withdrawal areas or national monuments for federal lands outside the withdrawal area or national monument but that are within the boundaries of and affect any of our properties, or similar actions, could adversely impact our affected properties or our ability to operate our affected properties.
There are risks associated with the Company’s joint venture operations and projects.
Although the Company holds a majority interest in a joint venture formed to hold the Alta Mesa Project, enCore faces risks that major decisions affecting the Alta Mesa Project may require the consent of or agreement with Boss pursuant to the joint venture agreement.
From time to time, the Company may enter into other joint venture or shared ownership arrangements with third parties to develop and/or operate its projects.
The success and timing of these operations and projects depend on a number of factors that may be outside of our control, including the financial resources of our partners and the objectives and interests of our partners. While joint venture partners may generally reach consensus regarding the direction and operation of the operation or project, there are no assurances that this will always be the case or that future demands and expectations will continue to align. Failure of joint venture partners to agree on matters requiring consensus may lead to development or operational delays, failure to obtain necessary permits or approvals in an efficient manner or at all, remedies under dispute resolution mechanisms, or the inability to progress with production at the relevant operation or development of the relevant project in accordance with expectations or at all, which could materially affect the operation or development of such projects or operations and our business and financial condition.
Risks Related to Taxation
If the Company is characterized as a passive foreign investment company, U.S. Holders may be subject to adverse U.S. federal income tax consequences.
Prospective U.S. investors should be aware that they could be subject to certain adverse U.S. federal income tax consequences in the event that the Company is classified as a “passive foreign investment company” (a “PFIC”) for U.S. federal income tax purposes. The determination of whether a corporation is a PFIC for a taxable year depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations, and the determination will depend on the composition of the corporation’s income, expenses and assets from time to time and the nature of the activities performed by the corporation’s officers and employees. Based on an analysis of the Company’s activities and income and assets, the Company believes that it was a PFIC for its taxable year ended December 31, 2025, and may continue to be classified as a PFIC for the current taxable year and the foreseeable future. A prospective investor should consult its own tax advisor regarding the likelihood and consequences of the Company being treated as a PFIC for U.S. federal income tax purposes, including the advisability of making certain elections that may mitigate certain possible adverse U.S. federal income tax consequences but that may result in an inclusion of gross income without receipt of such income.
We are subject to Canadian tax on our worldwide income.
We are deemed to be a resident of Canada for Canadian federal income tax purposes by virtue of being organized under the laws of British Columbia, a province of Canada. Accordingly, we are subject to Canadian taxation on our worldwide income, in accordance with the rules set forth in the Income Tax Act (Canada) (the “Tax Act”) generally applicable to corporations residing in Canada.
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Dividends, if ever paid, on the common shares are subject to Canadian withholding tax.
It is currently not anticipated that we will pay any dividends on our common shares in the foreseeable future. Dividends received by shareholders who are residents of the U.S. (“U.S. Holders”) will be subject to Canadian withholding tax. Any dividends may not qualify for a reduced rate of withholding tax under the U.S.-Canada Treaty. For U.S. federal income tax purposes, a U.S. Holder may elect for any taxable year to receive either a credit or a deduction for all foreign income taxes paid by the holder during the year. Dividends paid on the common stock will be treated as foreign-source income, and generally will be treated as “passive category income” or “general category income” for U.S. foreign tax credit purposes. Subject to certain limitations, a U.S. Holder should be able to take a deduction for the U.S. Holder’s Canadian tax paid, provided that the U.S. Holder has not elected to credit other foreign taxes during the same taxable year.
Dividends received by Non-U.S. Holders who are not residents of Canada for purposes of the Tax Act will be subject to Canadian withholding tax. These dividends may qualify for a reduced rate of Canadian withholding tax under any income tax treaty otherwise applicable to our shareholders, subject to examination of the relevant treaty.
Each of our shareholders should seek tax advice, based on such shareholder’s particular facts and circumstances, from an independent tax advisor.
Changes in tax laws may affect us and our shareholders.
There can be no assurance that our Canadian and U.S. federal income tax treatment or an investment in us will not be modified, prospectively or retroactively, by legislative, judicial or administrative action, in a manner adverse to us or our shareholders.
Risks Related to enCore’s common shares
The issuance of additional common shares may dilute shareholders’ interest in the Company, including pursuant to the conversion of our Convertible Senior Notes, and may affect the trading price of our common shares .
enCore may require additional funds to fund its exploration and development programs and potential acquisitions. If enCore raises additional funding by issuing additional equity securities, such financing may substantially dilute the interests of its shareholders. The Convertible Senior Notes are convertible at the option of the holders upon the occurrence of certain events and/or during certain periods. Upon the conversion of the Convertible Senior Notes, we will pay or deliver, as the case may be, cash, common shares or a combination of cash and common shares, at our election. The issuance of common shares upon the conversion of our Convertible Senior Notes may dilute the ownership interests of existing shareholders. In addition, the existence of the Convertible Senior Notes may encourage short selling by market participants that engage in hedging or arbitrage activity, and anticipated conversion of the Convertible Senior Notes into common shares could depress the price of our common shares.
enCore may also issue additional common shares in the future pursuant to proposed acquisitions and on the exercise of its outstanding stock options and warrants.
Sales of substantial amounts of enCore’s common shares, or the availability of such common shares for sale, could adversely affect the prevailing market prices for enCore’s securities. A decline in the market prices of enCore’s securities could impair its ability to raise additional capital through the sale of new common shares should enCore desire to do so.
The capped call transactions related to our Convertible Senior Notes may affect the value of our common shares.
In connection with our Convertible Senior Notes offering, we entered into capped call transactions with option counterparties. The capped call transactions are expected generally to reduce the potential dilution to our common shares upon conversion of the Convertible Senior Notes. Further, if the market price per share of our common share exceeds the cap price of the capped call transactions ($4.5150), there would nevertheless be dilution to the extent that such market price exceeds the cap price of the capped call transactions. Additionally, in connection with establishing the capped call transactions, the option counterparties may have entered into various derivative transactions with respect to our common shares. The option counterparties may modify their hedge positions by entering into or unwinding various derivatives with respect to our common shares and/or purchasing or selling our common shares or other securities of ours in secondary market transactions. This activity could cause or hinder an increase or a decrease in the market price of our common shares. The effect, if any, of these transactions and activities on the market price of our common shares will depend in part on market conditions and cannot be ascertained at this time, but these activities could adversely affect the market price of our common shares.
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The market price for common shares cannot be assured and is subject to volatility.
Securities markets have experienced a high level of price and volume volatility, and the market price of securities of many companies has experienced wide fluctuations which have not necessarily been related to the operating performance, underlying asset values or prospects of such companies.
In the past, following periods of volatility in the market price of a company’s securities, shareholders have often instituted class action securities litigation against those companies. For example, we currently are involved in a federal securities class action litigation, as described further in Note 10 - Commitments and Contingencies. Such litigation could result in substantial costs and diversion of management attention and resources, which could significantly harm enCore’s profitability and reputation.
enCore has never paid dividends and does not currently intend to do so in the foreseeable future. If our share price does not appreciate, our investors could potentially lose on their investment in our common shares.
enCore has never paid cash dividends on its common shares. enCore currently intends to retain its future earnings, if any, to fund the development and growth of its business, and does not anticipate paying any cash dividends on its common shares for the foreseeable future. As a result, shareholders will have to rely on capital appreciation, if any, to earn a return on investment in any common shares in the foreseeable future. Furthermore, enCore may in the future become subject to contractual restrictions on, or prohibitions against, the payment of dividends.
Our common shares are listed on Nasdaq, which subjects us to various listing standards, noncompliance of which could result in the delisting of our common shares, which could result in lower trading volumes and liquidity in the United States.
Our common shares began trading on Nasdaq on January 2, 2024. Continued listing of a security on Nasdaq is conditioned upon compliance with various listing standards. Failure to comply with Nasdaq’s continued listing standards could result in Nasdaq delisting our common shares resulting in our common shares trading in the less liquid over-the-counter market in the United States.
If Nasdaq delists our common shares, investors may face material adverse consequences including, but not limited to, a lack of trading market for our securities in the United States, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional financing to fund our operations.
Moreover, even to the extent our common shares remain listed on Nasdaq, there can be no assurance an active and liquid trading market for our common shares will develop or be maintained.
General Risks
Global financial conditions and risks could materially impact our ability to raise equity or obtain debt and impact global supply chains, which could adversely impact the Company’s operations and financial condition.
The development and ongoing operation of mines requires a substantial amount of capital prior to the commencement of, and in connection with, the production of uranium. Such capital requirements relate to the costs of, among other things, acquiring mining rights and properties, obtaining government permits, exploration and delineation drilling to determine the underground configuration of a deposit, designing and constructing the mine and processing facilities, purchasing and maintaining mining equipment and complying with financial assurance requirements established by various regulatory agencies for the future restoration and reclamation activities for each project. There is a risk that cash flow from operations will be insufficient to meet current and future obligations, fund development and construction projects, and that additional outside sources of capital will be required. The volatility of global capital markets, including the general economic slowdown in the mining sector, has generally made the raising of capital by equity or debt financing more difficult. The Company may be dependent upon capital markets to raise additional financing in the future. As such, the Company is subject to liquidity risks in meeting its operating expenditure requirements and future development cost requirements in instances where adequate cash positions are unable to be maintained or appropriate financing is unavailable. If the Company is unable to raise equity or obtain loans and other credit facilities in the future and on terms favorable to the Company, these levels of volatility persist or there is a further economic slowdown, the Company’s operations, the Company’s ability to raise capital and the trading price of the Company’s securities could be adversely impacted.
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As the Company’s operations expand and reliance on global supply chains increases, the impact of pandemics, significant geopolitical risk and conflict globally may have a sizeable and unpredictable impact on the Company’s business, financial condition and operations. Russia’s invasion of Ukraine, including the global response to Russia as it relates to sanctions, trade embargos and military support, have resulted in significant uncertainty as well as economic and supply chain disruptions. Should such global conflicts and responses go on for an extended period of time or should other geopolitical disputes and conflicts and responses thereto emerge in other regions that produce uranium or other energy, this could result in material adverse effects to the Company.
General inflationary pressures may impact the Company’s costs and affect our results of operations.
Inflationary pressure may also affect the Company’s labor, commodity, and other input costs, which could affect the Company’s financial condition. Operational costs may be affected by continuing inflation and cost-of-goods due to supply chain issues as well as the possible need to utilize a greater level of contractor services if required staffing is unavailable or cannot timely be hired and trained, resulting in higher costs for key inputs required for its operations, which may be directly through higher transportation costs, as well as indirectly through higher costs of products that rely on energy, which could result in material adverse effects to the Company.
We are dependent on information technology systems, which are subject to certain risks, including cybersecurity risks and data leakage risks associated with implementation and integration.
The Company’s operations depend upon the availability, capacity, reliability and security of its information technology (“IT”) infrastructure, and its ability to expand and update this infrastructure as required, to conduct daily operations. enCore relies on various IT systems in all areas of its operations, including financial reporting, contract management, exploration and development data analysis, human resource management, regulatory compliance and communications with employees and third parties.
These IT systems could be subject to network disruptions caused by a variety of sources, including computer viruses, security breaches and cyber-attacks, as well as network and/or hardware disruptions resulting from incidents such as unexpected interruptions or failures, natural disasters, fire, power loss, vandalism and theft. The Company’s operations also depend on the timely maintenance, upgrade and replacement of networks, equipment, IT systems and software, as well as pre-emptive expenses to mitigate the risks of failures.
The ability of the IT function to support the Company’s business in the event of any such occurrence and the ability to recover key systems from unexpected interruptions cannot be fully tested. There is a risk that, if such an event actually occurs, the Company’s continuity plans may not be adequate to immediately address all repercussions of the disaster. In the event of a disaster affecting a data center or key office location, key systems may be unavailable for a number of days, leading to inability to perform some business processes in a timely manner. As a result, the failure of enCore’s IT systems or a component thereof could, depending on the nature of any such failure, adversely impact the Company’s reputation and results of operations.
Although to date the Company has not experienced any material losses relating to cyber-attacks or other information security breaches, there can be no assurance that the Company will not incur such losses in the future. Unauthorized access to enCore’s IT systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to the Company’s business activities or its competitive position. Further, disruption of critical IT services, or breaches of information security, could have a negative effect on the Company’s operational performance and its reputation. The Company’s risk and exposure to these matters cannot be fully mitigated because of, among other things, the evolving nature of these threats. As a result, cyber security and the continued development and enhancement of controls, processes and practices designed to protect systems, computers, software, data and networks from attack, damage or unauthorized access remain a priority.
The Company applies technical and process controls in line with industry-accepted standards to protect information, assets and systems; however, these controls may not adequately prevent cyber-security breaches. There is no assurance that the Company will not suffer losses associated with cyber-security breaches in the future and may be required to expend significant additional resources to investigate, mitigate and remediate any potential vulnerabilities. As cyber threats continue to evolve, the Company may be required to expend additional resources to continue to modify or enhance protective measures or to investigate and remediate any security vulnerabilities.
Our business is subject to the U.S. Foreign Corrupt Practices Act and other extraterritorial and national anti-bribery laws and regulations, a breach or violation of which could lead to substantial sanctions and civil and criminal
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prosecution, as well as fines and penalties, litigation, loss of licenses or permits and other collateral consequences and reputational harm.
The Company is subject to anti-bribery and anti-corruption laws, including the United States Foreign Corrupt Practices Act of 1977, as amended and the Corruption of Foreign Public Officials Act (Canada). Failure to comply with these laws could subject the Company to, among other things, reputational damage, civil or criminal penalties, other remedial measures and legal expenses which could adversely affect the Company’s business, results from operations, and financial condition. It may not be possible for the Company to ensure compliance with anti-bribery and anti-corruption laws in every jurisdiction in which its employees, agents, sub-contractors or joint venture partners are located or may be located in the future.
The Company is a public issuer in both the United States and Canada. The board of directors (the “Board”) and management must devote time and resources to compliance initiatives, corporate governance practices and securities rules and regulations that impose various requirements on both Canadian and U.S. public companies. These additional costs and management attention could negatively impact our business, financial condition and results of operations.
As a public issuer in Canada, the Company is subject to the reporting requirements and rules and regulations under Canadian securities laws and the rules of TSX-V. As a public issuer in the United States, the Company is also subject to the rules and regulations of the SEC and Nasdaq and the reporting requirements of the Exchange Act. Application of both existing or new U.S. or Canadian regulatory requirements may have adverse consequences on our ability to issue securities to raise capital or as consideration for acquisitions.
As a public company, there are costs associated with legal, accounting and other expenses related to regulatory compliance in Canada as well as compliance with the U.S. securities legislation and the rules and policies of Canadian Securities Administrators, TSX-V, the SEC and Nasdaq, which require reporting and listed companies to, among other things, adopt corporate governance and related practices, and to continuously prepare and disclose material information, all of which add to a company’s legal and financial compliance costs. Complying with these U.S. and Canadian statutes, regulations and requirements may occupy a significant amount of time of the Board and management.
We are a “smaller reporting company” under the federal securities laws and will be subject to reduced public company reporting requirements.
As a smaller reporting company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “smaller reporting companies,” including, but not limited to, reduced disclosure obligations regarding executive compensation in our proxy statements. If we do not qualify as a smaller reporting company, we may incur additional costs complying with enhanced reporting requirements that are applicable to other public companies that are not smaller reporting companies.
We have identified material weaknesses in our internal controls over financial reporting. If we are unable to remediate these material weaknesses, or if we experience additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, we may not be able to accurately or timely report our financial results, in which case our business may be harmed and, investors may lose confidence in the accuracy and completeness of our financial reports, and as a result, the price of our common shares may be adversely affected.
In the course of its assessment of the effectiveness of our internal control over financial reporting as of December 31, 2024, our management identified material weaknesses in our internal control over financial reporting as of December 31, 2024. During 2025, we developed and executed a comprehensive remediation plan; however, certain controls have not yet been in operation for sufficient duration across multiple reporting periods to conclude full remediation as of December 31, 2025 (see Item 9A to this Annual Report for more information). A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. As a result of these material weaknesses, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2025. If we fail to remediate the material weaknesses or experience additional material weaknesses in the future or fail to otherwise maintain effective financial reporting systems and processes, we may be unable to accurately and timely report our financial results or comply with the requirements of being a public company, which could cause investors to lose confidence in our financial information and the price of our common shares could decline. We cannot assure you that the remediation measures we have taken to date and intend to continue to take, including testing the design and operating effectiveness after such controls have operated for a sufficient period of time, will be sufficient to remediate the material weaknesses. Moreover, we cannot be certain that we will not in the future have additional material weaknesses in our internal control over financial reporting, or that we will successfully remediate any that we find.
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The SEC’s disclosure requirements for Mineral Reserves and Mineral Resources, as codified in Subpart 1300 of Regulation S-K 1300, create ambiguity for issuers required to comply with both the requirements of S-K 1300 and NI 43-101, and may result in increased compliance costs for the Company.
S-K 1300, as promulgated by the SEC and effective starting in 2021, required that the Company disclose specific information related to its material mining operations, including its Mineral Resources and Mineral Reserves. While S-K 1300 is substantively the same as NI 43-101, it is relatively new compared to NI 43-101 and, thus, remains subject to unknown interpretations that could require the Company to incur substantial costs associated with compliance. Where substantive disclosure in one regulatory scheme is more restrictive/stringent than in the other, the Company opted to take the more restrictive/stringent approach in its technical reports. NI 43-101 has a prescribed format, whereas S-K 1300 does not; as such, the Company’s technical reports follow the formatting requirements of NI 43-101. Any further revisions to, or interpretations of, S-K 1300 or NI 43-101 could result in the Company incurring unforeseen costs associated with compliance, both in the United States and in Canada.
U.S. investors may not be able to obtain enforcement of civil liabilities against the Company.
The enforcement by investors of civil liabilities under the U.S. federal or state securities laws may be affected adversely by the fact that the Company is governed by the BCBCA. It may not be possible for investors to effect service of process within the United States on certain of its directors and officers or enforce judgments obtained in the U.S. courts against the Company or certain of the Company’s directors and officers based upon the civil liability provisions of United States federal securities laws or the securities laws of any state of the United States. There is some doubt as to whether a judgment of a U.S. court based solely upon the civil liability provisions of U.S. federal or state securities laws would be enforceable in Canada against the Company or its directors and officers. There is also doubt as to whether an original action could be brought in Canada against the Company or its directors and officers to enforce liabilities based solely upon U.S. federal or state securities laws.
Changes in accounting rules and other policy or regulatory changes could occur at any time and could impact us in significantly negative ways that we are unable to predict or protect against.
The SEC, Financial Accounting Standards Board and other regulatory bodies that establish the accounting rules applicable to us have proposed or enacted a wide array of changes to accounting rules over the last several years. Moreover, in the future, these regulators may propose additional changes that we do not currently anticipate. Changes to accounting rules that apply to us could significantly impact our business or our reported financial performance in negative ways that we cannot predict or protect against. We cannot predict whether any changes to current accounting rules will occur or what impact any codified changes will have on our business, results of operations, liquidity or financial condition.
Changes in the U.S. presidential administration and changes in Congress could result in significant policy changes or regulatory uncertainty in our industry. While it is not possible to predict when and whether significant policy or regulatory changes would occur, any such changes on the federal, state or local level could significantly impact, among other things, our operating expenses, our ability to obtain the required licenses and permits in a timely manner, the availability of financing, interest rates, the economy and the geopolitical landscape. To the extent that the government administration takes action by proposing and/or passing regulatory policies that could have a negative impact on our industry, such actions may have a material adverse effect on our business, results of operations, liquidity and financial condition.
Our proprietary data, technology and intellectual property may be compromised or lost, which could result in decreased competitive advantage and/or loss to the value of such assets.
With the ever-increasing reliance on technology throughout our operations, including developments of proprietary technology and intellectual property by the Company and/or it consultants, risks of theft, appropriation or other loss of such technology and assets and/or our proprietary data pose a risk to our competitive advantage and business and financial results. We take what we believe to be reasonable steps to protect these proprietary technologies and intellectual property, including contractually and by efforts to obtain patents or trade rights where possible, but there can be no assurance that all such measures will be sufficient or successful.
Investors may experience future dilution as a result of additional debt and equity offerings.
To raise additional capital, we may in the future offer additional common shares or other securities convertible into or exchangeable for our common shares at prices that may not be the same as the price per share as the shares an investor has
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previously purchased, and investors purchasing shares or other securities in the future could have rights superior to existing shareholders.
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Item 1B. Unresolved Staff Comments
None
Item 1C. Cybersecurity
We rely on information technology to operate our business. We have endpoint and other protection systems, and incident response processes, both internally and through third-party experts designed to protect our information technology systems. These established processes assist us to continuously assess and identify threats to our systems and minimize impact to our business in the event of a breach or other security incident. Additionally, the Company has implemented numerous information technology policies and procedures concerning cybersecurity matters, which include policies that directly or indirectly relate to encryption standards, antivirus protection, remote access, multi-factor authentication, confidential information and the use of the internet, social media, email and wireless and personal devices for both Company business and personal matters while utilizing Company resources. Employees receive required annual cybersecurity training and additional training is provided on a regular basis. Periodic educational notices are also disseminated to all personnel. Additionally, as our systems are modified and upgraded, all personnel are notified, with instruction as appropriate.
Together with our third-party consultants, these processes and policies are reviewed on a periodic basis [and no less frequently than annually] to identify potential cybersecurity threats and vulnerabilities. This assessment includes, among other things, evaluating the nature, sensitivity and location of information the Company collects, processes and stores and the resiliency of the underlying technologies, the validity and effectiveness of the Company’s security policies, controls and processes and the cybersecurity preparedness of the third-party vendors used by the Company. In addition, the third-party consultants conduct [annual penetration testing (internal and external)] as well as routine phishing testing to validate the effectiveness of technical controls and identify areas for improvement. Based on these assessments, if needed, these policies and policies are updated and re-approved by the appropriate members of management, including our Chief Executive Officer and General Counsel.
As any new threat to security may be identified internally or by our third-party cybersecurity experts, our Chief Executive Officer and General Counsel are notified, with instruction to increase awareness of the threat and how to react if such a threat or actual breach appears to be encountered. Both our Chief Executive Officer and General Counsel rely on prior experience and expertise of their reports, including internal employees and third-party cybersecurity experts, if applicable, in determining cybersecurity threats. The Audit Committee receives prompt and timely information from our Chief Executive Officer and General Counsel regarding any cybersecurity incident that meets established reporting thresholds, as well as ongoing updates regarding any such incident until it has been addressed.
Governance
Our Board oversees the risks involved in our operations as part of its general oversight function, integrating risk management into the Company’s compliance policies and procedures. With respect to cybersecurity, the Audit Committee of the Board has the ultimate oversight responsibility relating to risk management of cybersecurity.
Among other things, the Audit Committee discusses with management, including the Chief Executive Officer and General Counsel, the Company’s major policies with respect to risk assessment and risk management, including cyber security, as they relate to the integrity of the Company’s accounting and financial reporting processes and the Company’s compliance with legal and regulatory requirements.
In addition to its other responsibilities, the Board as a whole oversees operational information technology risks, including cybersecurity, as they relate to the technical aspects of the Company’s operations. The Audit Committee and the full Board receive quarterly reports from the Chief Executive Officer and General Counsel, supported by relevant cross-functional leaders, on information technology matters. The reports address upgrades to hardware, software, and IT systems throughout the Company, and include the identification of IT and cybersecurity risks. Security scores, risk management, mitigation measures, third-party reviews and relevant technology and information security trends are routinely presented. As discussed above, we maintain endpoint and other protection systems, and incident response processes, both internally and through third-party experts. As these systems, processes, training, and upgrades are implemented, updates are provided to the Audit Committee and full Board.
Risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected, and not reasonably likely to materially affect us, including our business strategy, results of operations or financial statements. However, the risk of cybersecurity threats could be significant if the cyber-attack disrupts the Company’s
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critical operations, service or financial systems. For additional information regarding risks from cybersecurity threats, please refer to Item 1A, “Risk Factors,” We are dependent on information technology systems, which are subject to certain risks, including cybersecurity risks and data leakage risks associated with implementation and integration” above.
Item 2. Properties
Please refer to Item 1. “Business and Properties” of this Annual Report for information concerning our properties.
Item 3. Legal Proceedings
For a discussion of the legal proceedings of the Company, see Note 10 – Commitments and Contingencies to the consolidated financial statements below..
Item 4. Mine Safety Disclosures
Our operations and other activities are not subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977.
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
The authorized capital of the Company consists of an unlimited number of common shares without par value and an unlimited number of Preferred Shares without par value (referred to herein as the “enCore Preferred Shares”). As at December 31, 2025, there were 187,354,424 common shares issued and outstanding and held by 210 record holders. As at the date of this Annual Report on Form 10-K, there are 194,216,153 common shares issued and outstanding. The Company had no Preferred Shares issued and outstanding as at the date of this Annual Report on Form 10-K. The number of record holders is based on the records of Computershare Investor Services Inc., who serves as our transfer agent. The number of holders does not include individuals or entities who beneficially own shares but whose shares are held of record by a broker or clearing agency, but does include each such broker or clearing agency as one record holder. Our common shares are listed on the Nasdaq Capital Market LLC (“Nasdaq”) and the TSX Venture Exchange (“TSX-V”) under the trading symbol “EU”.
As of the date of this Annual Report, enCore has 6,663,558 stock options issued and outstanding.
As of December 31, 2025, the Company had 19,741,640 share purchase warrants to purchase common shares of the Company’s outstanding as follows:

Number Issued |  | Weighted Average Exercise Price (C$) |  | Expiry Date
3,835,440 |  | 4.05 |  | February 2026
15,906,200 |  | 3.75 |  | February 2026

As of the date of this Annual Report, enCore had no warrants issued and outstanding.
Dividend Policy
We have never declared cash dividends on our common shares. We anticipate that we will retain any earnings to support operations and to finance the growth of our business. Therefore, we do not expect to pay cash dividends in the foreseeable future. Any further determination to pay cash dividends will be at the discretion of our Board of Directors and will be
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dependent on the financial condition, operating results, capital requirements, and other factors that our Board of Directors deems relevant.
Unregistered Sales of Equity Securities
The following represents securities sold by the Company in the two years ended December 31, 2025 and 2024 which were not registered under the Securities Act. Included are new issuances, securities issued in exchange for property, services or other securities, securities issued upon conversion or vesting of other Company securities. The Company issued all of the securities listed below pursuant to the exemption from registration provided by Rule 701 of the Securities Act, Section 4(a)(2) of the Securities Act or Regulation D or Regulation S promulgated thereunder.
On February 15, 2023, the Company closed the acquisition of the Alta Mesa Project for $60 million in cash and a $60 million secured convertible promissory note (the “Note”). The Note has a two (2) year term and bears interest at a rate of 8% per annum payable on June 30 th and December 31 st of each year during the term. The Note is convertible at the election of the holder, to acquire common shares of enCore at a price of C$2.9103 per share. The holder agreed not to transact with the common shares of enCore received on conversion of the Note, including hedging and short sales, with exceptions for sale transactions of up to C$10 million in value in any 30-day period, block trades and underwritten distributions. In addition, the holder agreed to standard standstill provisions restricting additional acquisitions of enCore securities. On February 7, 2024, the full outstanding principal amount of the Note in the amount of $20 million was converted into 6,872,143 common shares of the Company. The common shares were issued in reliance upon the exemptions from registration afforded by Section 4(a)(2) and Rule 506(b) promulgated under the Securities Act, because (i) the issuances were not made by general solicitation or advertising and (ii) the issuances were made only to “accredited investors” (as such term is defined in Rule 501(a) of Regulation D under the Securities Act).
On February 26, 2024, the Company issued 2,564,102 common shares of enCore at a price of $3.90 per share to Boss in connection with the joint venture in the Alta Mesa Project. The common shares were sold pursuant to the exemption from the registration requirements of the Securities Act provided by Rule 903 of Regulation S under the Securities Act. The common shares were issued in reliance upon the exemptions from registration afforded by Section 4(a)(2) and Rule 506(b) promulgated under the Securities Act, because (i) the issuances were not made by general solicitation or advertising and (ii) the issuances were made only to “accredited investors” (as such term is defined in Rule 501(a) of Regulation D under the Securities Act).
During the fiscal year ended December 31, 2025, the Company issued 190,000 common shares pursuant to the exercise of warrants for gross proceeds of $654. During the fiscal year ended December 31, 2024, the Company issued 8,781,985 common shares pursuant to the exercise of warrants for gross proceeds of $25,471. The common shares were sold pursuant to the exemption from the registration requirements of the Securities Act provided by Rule 903 of Regulation S promulgated under the Securities Act and Rule 4(a)(2) of the Securities Act because (i) the issuances were to investors outside the United States and/or (ii) in a transaction not involving any public offering.
Issuer Repurchases of Equity Securities
The Company did not purchase its own equity securities during the fiscal quarter ended December 31, 2025.
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
The following portion of this summary is generally applicable to a holder who acquires, as beneficial owner, our common shares, and who, for purposes of the Income Tax Act (Canada) and the regulations promulgated thereunder (the “Tax Act”) and at all relevant times, is neither resident nor deemed to be resident in Canada and does not use or hold, and will not be deemed to use or hold, common shares in a business carried on in Canada (each, a “Non-Resident Holder”). The term “American Holder,” for the purposes of this summary, means a Non-Resident Holder who, for purposes of the Canada-U.S. Tax Convention, is at all relevant times a resident of the United States and is a “qualifying person” within the meaning of the Canada-U.S. Tax Convention eligible for the full benefits of the Canada-U.S. Tax Convention. In some circumstances, persons deriving amounts through fiscally transparent entities (including limited liability companies) may be entitled to benefits under the Canada-U.S. Tax Convention. American Holders are urged to consult their own tax advisors to determine their entitlement to benefits under the Canada-U.S. Tax Convention and related compliance requirements based on their particular circumstances.
Special considerations, which are not discussed in this summary, may apply to a Non-Resident Holder that is an insurer that carries on an insurance business in Canada and elsewhere or an authorized foreign bank (as defined in the Tax Act). Such Non-Resident Holders should consult their own advisors.
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This summary is based upon the provisions of the Tax Act in force as of the date hereof, all specific proposals to amend the Tax Act that have been publicly and officially announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (the “Proposed Amendments”) and management’s understanding of the current administrative policies and assessing practices of the Canada Revenue Agency (the “CRA”) published in writing by it prior to the date hereof. This summary assumes the Proposed Amendments will be enacted in the form proposed. However, no assurance can be given that the Proposed Amendments will be enacted in their current form, or at all. This summary is not exhaustive of all possible Canadian federal income tax considerations and, except for the Proposed Amendments, does not take into account or anticipate any changes in the law or any changes in the CRA’s administrative policies or practices, whether by legislative, governmental, or judicial action or decision, nor does it take into account or anticipate any other federal or any provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein.
Non-Resident Holders should consult their own tax advisors with respect to an investment in our common shares. This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any prospective purchaser or holder of our common shares, and no representations with respect to the income tax consequences to any prospective purchaser or holder are made. Consequently, prospective purchasers or holders of our common shares should consult their own tax advisors with respect to their particular circumstances.
Currency Conversion
Generally, for purposes of the Tax Act, all amounts relating to the acquisition, holding, or disposition of our common shares, including dividends, adjusted cost base and proceeds of disposition, must be converted into Canadian Dollars based on the exchange rates as determined in accordance with the Tax Act. The amounts subject to withholding tax and any capital gains or capital losses realized by a Non-Resident Holder may be affected by fluctuations in the value of the Canadian Dollar relative to other currencies.
Taxation of Dividends
Subject to an applicable tax treaty or convention, dividends paid or credited, or deemed to be paid or credited, to a Non-Resident Holder on the common shares will be subject to Canadian withholding tax under the Tax Act at the rate of 25% of the gross amount of the dividend. Such rate is generally reduced under the Canada-U.S. Tax Convention to 15% if the beneficial owner of such dividend is an American Holder. The rate of withholding tax is generally further reduced to 5% if the beneficial owner of such dividend is an American Holder that is a company that owns, at least 10% of the voting shares of the Company. Non-Resident Holders should consult their own tax advisors to determine their entitlement to benefits under any applicable tax treaty or convention based on their particular circumstances.
Disposition of Common Shares
A Non-Resident Holder will not be subject to tax under the Tax Act in respect of any capital gain realized by such Non-Resident Holder on a disposition of common shares, unless the common shares constitute “taxable Canadian property” (as defined in the Tax Act) of the Non-Resident Holder at the time of the disposition and are not “treaty-protected property” (as defined in the Tax Act) of the Non-Resident Holder at the time of the disposition.
Generally, provided the common shares are listed on a “designated stock exchange” as defined in the Tax Act (which currently includes the TSXV and Nasdaq) at the time of disposition, the common shares will not constitute taxable Canadian property of a Non-Resident Holder, unless at any time during the 60-month period immediately preceding the disposition the following two conditions are met concurrently: (a) the Non-Resident Holder, persons with which the Non-Resident Holder does not deal at arm’s length, partnerships whose members include, either directly or indirectly through one or more partnerships, the Non-Resident Holder and/or persons which do not deal at arm’s length with the Non-Resident Holder, or any combination of the foregoing, owned 25% or more of the issued shares of any class or series of shares of the capital stock of the Company, and (b) more than 50% of the fair market value of the common shares was derived directly or indirectly, from one or any combination of real or immovable property situated in Canada, “Canadian resource properties”, “timber resource properties” (each as defined in the Tax Act), and options in respect of or interests in, or for civil law rights in, any such property (whether or not such property exists). Notwithstanding the foregoing, common shares may also be deemed to be “taxable Canadian property” of a Non-Resident Holder in other circumstances under the Tax Act.
The common shares of an American Holder will generally constitute “treaty-protected property” for purposes of the Tax Act unless the value of the common shares is derived principally from real property situated in Canada. For this purpose, “real property” has the meaning that term has under the laws of Canada and includes any option or similar right in respect thereof and in any case, includes usufruct of real property, rights to explore for or to exploit mineral deposits, sources and
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other natural resources and rights to amounts computed by reference to the amount or value of production from such resources.
If common shares are taxable Canadian property of a Non-Resident Holder and are not treaty-protected property of the Non-Resident Holder at the time of their disposition, the Non-Resident Holder may owe Canadian income tax on any taxable capital gains realized and should consult their own tax advisor with respect to the procedures that must be followed when disposing of taxable Canadian property.
Non-Resident Holders whose common shares may constitute taxable Canadian property should consult their own advisors.
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
The following is a general summary of certain U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from the ownership and disposition of common shares. This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder. In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such holder (as discussed below), including specific tax consequences to a holder under an applicable tax treaty. Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any holder. This summary is limited to U.S. federal income tax considerations, and does not address the U.S. federal alternative minimum, net investment income, U.S. federal estate and gift, U.S. state and local, or non-U.S. tax consequences of the ownership and disposition of such common shares. Except as specifically set forth below, this summary does not discuss applicable income tax reporting requirements. Each holder should consult its own tax advisor regarding all U.S. federal, U.S. state and local, and non-U.S. tax consequences of the ownership and disposition of common shares.
No opinion from U.S. legal counsel or ruling from the U.S. Internal Revenue Service (“IRS”) has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the ownership and disposition of common shares. This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary. In addition, because the authorities on which this summary is based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the positions taken in this summary.
This summary does not address the U.S. federal income tax consequences to any particular person of the ownership and disposition of common shares. Each holder should consult its own tax advisor regarding all U.S. federal, U.S. state and local, and non-U.S. tax consequences of the ownership and disposition of common shares.
Scope of This Disclosure
Authorities
This summary is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), proposed, final and temporary U.S. Treasury Regulations, published rulings of the IRS, published administrative positions of the IRS, and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this Annual Report. Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a prospective or retroactive basis which could affect the U.S. federal income tax considerations described in this summary. This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive or prospective basis.
U.S. Holders
For purposes of this summary, the term “U.S. Holder” means a beneficial owner of common shares that is for U.S. federal income tax purposes:
•an individual who is a citizen or resident of the United States;
•a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof, or the District of Columbia;
•an estate the income of which is subject to U.S. federal income tax regardless of its source; or
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•a trust that (a) is subject to the primary supervision of a court within the United States and the control of one or more U.S. persons for all substantial decisions or (b) has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a U.S. person.
Non-U.S. Holders
Also, for purposes of this discussion, a “Non-U.S. Holder” is any beneficial owner of common stock who is neither a U.S. Holder nor an entity classified as a partnership for U.S. federal income tax purposes. This summary does not address the U.S. federal income tax considerations applicable to Non-U.S. Holders relating to the acquisition, ownership and disposition of common shares. Accordingly, Non-U.S. Holders should consult their own tax advisors regarding the U.S. federal, U.S. state and local, and non-U.S. tax consequences (including the potential application of and operation of any tax treaties) relating to the acquisition, ownership, and disposition of common shares.
U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed
This summary does not address the U.S. federal income tax consequences of the ownership and disposition of common shares that are subject to special provisions under the Code, including holders that: (a) are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) are broker-dealers, dealers, or traders in securities or currencies that elect to apply a mark-to-market accounting method; (d) have a “functional currency” other than the U.S. dollar; (e) own common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) acquired common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) hold common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); (h) own, directly, indirectly, or by attribution, 5% or more, by voting power or value, of the outstanding common shares; (i) are required to accelerate the recognition of any item of gross income for U.S. federal income tax purposes with respect to common shares as a result of such item being taken into account in an applicable financial statement; (j) acquired common shares by gift or inheritance; (k) are certain former citizens or long-term residents of the United States; (l) are pension plans; (m) are integral parts or controlled entities of foreign sovereigns; or (n) are passive foreign investment companies and corporations that accumulate earnings to avoid U.S. federal income tax. Holders that are subject to special provisions under the Code, including those holders described immediately above, should consult their own tax advisors regarding all U.S. federal, U.S. state and local, and non-U.S. tax consequences relating to the ownership and disposition of common shares.
If an entity or arrangement that is classified as a partnership (including any other “pass-through” entity) for U.S. federal income tax purposes holds common shares, the U.S. federal income tax consequences to such partnership and the partners (or owners) of such partnership of participating in the ownership and disposition of common shares generally will depend on the activities of the partnership and the status of such partners (or owners). This summary does not address the tax consequences to any such partnership or partner (or owner). Partners (or owners) of entities and arrangements that are classified as partnerships for U.S. federal, U.S. state and local, and non-tax purposes should consult their own tax advisors regarding the U.S. federal income tax consequences of the ownership and disposition of common shares.
U.S. Tax Considerations Relevant to the Ownership and Disposition of Common Shares
Distributions
We do not currently anticipate paying distributions on our common shares. Subject to the PFIC rules discussed below, a U.S. Holder that receives a distribution, including a constructive distribution, with respect to common shares will be required to include the amount of such distribution in gross income as a dividend (without reduction for any Canadian income tax withheld from such distribution) to the extent of the current or accumulated “earnings and profits” of the Company, as computed for U.S. federal income tax purposes. To the extent that a distribution exceeds the current and accumulated “earnings and profits” of the Company, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. Holder’s tax basis in the common shares and thereafter as a gain from the sale or exchange of such common shares(see “Sale, Exchange or Other Taxable Disposition of Common Shares” below). However, the Company does not intend to maintain the calculations of earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder should therefore assume that any distribution by the Company with respect to the common shares will constitute ordinary dividend income. Subject to applicable limitations, dividends paid by the Company to non-corporate U.S. Holders, including individuals, generally will be eligible for the preferential tax rates applicable to long-term capital gains for dividends, provided certain holding period and other conditions are satisfied, including that the Company not be classified as a PFIC (as discussed below) in the tax year of distribution or in the preceding tax year.
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Dividends received on common shares by corporate U.S. Holders will not be eligible for the “dividends received deduction”. The dividend rules are complex, and each U.S. Holder should consult its own tax advisor regarding the application of such rules.
Sale, Exchange or Other Taxable Disposition of Common Shares
Subject to the PFIC rules discussed below, upon the sale or other taxable disposition of common shares, a U.S. Holder generally will recognize capital gain or loss in an amount equal to the difference between (a) the amount of cash plus the fair market value of any property received and (b) its tax basis in such common shares sold or otherwise disposed of. Such gain generally will be treated as “U.S. source” for purposes of applying the U.S. foreign tax credit rules unless the gain is subject to tax in Canada and is re-sourced as “foreign source” under the Canada - US Tax Treaty and such U.S. Holder elects to treat such gain or loss as “foreign source” (see a more detailed discussion at “Foreign Tax Credit” below). Any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if, at the time of the sale or other disposition, such common shares are held for more than one year. Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust. There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation. Deductions for capital losses are subject to significant limitations under the Code.
Passive Foreign Investment Company Rules (PFIC)
If the Company is considered a PFIC within the meaning of Section 1297 of the Code at any time during a U.S. Holder’s holding period, then certain different and potentially adverse tax consequences would apply to such U.S. Holder’s acquisition, ownership and disposition of common shares.
PFIC Status of the Company
The Company generally will be a PFIC if, for a given tax year, (a) 75% or more of the gross income of the Company for such tax year is passive income or (b) 50% or more of the assets held by the Company either produce passive income or are held for the production of passive income, based on the fair market value of such assets. “Gross income” generally includes all revenues less the cost of goods sold plus income from investments and from incidental or outside operations or sources, and “passive income” includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of shares and securities, and certain gains from commodities transactions. Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all of a foreign corporation’s commodities are shares in trade or inventory, depreciable property used in a trade or business, or supplies regularly used or consumed in a trade or business, and certain other requirements are satisfied.
For purposes of the PFIC income test and asset test described above, if the Company owns, directly or indirectly, 25% or more of the total value of the outstanding shares of another corporation, the Company will be treated as if it (a) held a proportionate share of the assets of such other corporation and (b) received directly a proportionate share of the income of such other corporation. In addition, for purposes of the PFIC income test and asset test described above, “passive income” does not include any interest, dividends, rents or royalties that are received or accrued by the Company from a “related person” (as defined in Section 954(d)(3) of the Code), to the extent such items are properly allocable to the income of such related person that is not passive income.
Under certain attribution rules, if the Company is a PFIC, U.S. Holders will be deemed to own their proportionate share of any subsidiary of the Company which is also a PFIC (a “Subsidiary PFIC”), and will be subject to U.S. federal income tax on (a) a distribution on the shares of a Subsidiary PFIC and (b) a disposition of shares of a Subsidiary PFIC, both as if the U.S. Holder directly held the shares of such Subsidiary PFIC.
Based on an analysis of the Company’s activities and income and assets, the Company believes that it was a PFIC for its taxable year ended December 31, 2025, and may continue to be classified as a PFIC for the current taxable year and the foreseeable future. No opinion of legal counsel or ruling from the IRS concerning the status of the Company as a PFIC has been obtained or is currently planned to be requested. The determination of whether the Company (or a subsidiary of the Company) was, or will be, a PFIC for a tax year depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations. In addition, whether the Company (or subsidiary) will be a PFIC for any tax year depends on the assets and income of the Company (and each such subsidiary) over the course of each such tax year and, as a result, cannot be predicted with certainty as of the date of this document. Accordingly, there can be no assurance that the IRS will not challenge any determination made by the Company (or subsidiary) concerning its PFIC status or that the Company (and any subsidiary) was not, or will not be, a PFIC for any tax year. U.S. Holders should consult their own tax advisors regarding the PFIC status of the Company and any subsidiary of the Company.
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Default PFIC Rules under Section 1291 of the Code
If the Company is a PFIC, the U.S. federal income tax consequences to a U.S. Holder of the acquisition, ownership and disposition of common shares will depend on whether such U.S. Holder makes a qualified electing fund election (a “QEF Election”) or makes a mark-to-market election under Section 1296 of the Code (a “Mark-to-Market Election”) with respect to its common shares. A U.S. Holder that does not make either a QEF Election or a Mark-to-Market Election will be referred to in this summary as a “Non-Electing U.S. Holder”.
A Non-Electing U.S. Holder will be subject to the rules of Section 1291 of the Code with respect to (a) any gain recognized on the sale or other taxable disposition of the common shares and (b) any excess distribution paid on the common shares. A distribution generally will be an “excess distribution” to the extent that such distribution (together with all other distributions received in the current tax year) exceeds 125% of the average distributions received during the three preceding tax years (or during a U.S. Holder’s holding period for the common shares, if shorter).
If the Company is a PFIC, under Section 1291 of the Code any gain recognized on the sale or other taxable disposition of common shares (including an indirect disposition of shares of a Subsidiary PFIC), and any excess distribution paid on the common shares (or a distribution by a Subsidiary PFIC to its shareholder that is deemed to be received by a U.S. Holder) must be ratably allocated to each day of a Non-Electing U.S. Holder’s holding period for the common shares. The amount of any such gain or excess distribution allocated to the tax year of disposition or excess distribution and to years before the Company became a PFIC, if any, would be taxed as ordinary income. The amounts allocated to any other tax year would be subject to U.S. federal income tax at the highest tax rate applicable to ordinary income in each such year, and an interest charge would be imposed on the tax liability for each such year, calculated as if such tax liability had been due in each such year. A Non-Electing U.S. Holder that is not a corporation must treat any such interest paid as “personal interest”, which is not deductible.
If the Company is a PFIC for any tax year during which a Non-Electing U.S. Holder holds common shares, the Company will continue to be treated as a PFIC with respect to such Non-Electing U.S. Holder, regardless of whether the Company ceases to be a PFIC in one or more subsequent years. If the Company ceases to be a PFIC, a Non-Electing U.S. Holder may terminate this deemed PFIC status with respect to the common shares by electing to recognize gain (which will be taxed under the rules of Section 1291 of the Code discussed above) as if such common shares were sold on the last day of the last tax year for which the Company was a PFIC.
QEF Election
In the event the Company is a PFIC and a U.S. Holder makes a QEF Election for the first tax year in which its holding period of its common shares begins, such U.S. Holder generally will not be subject to the rules of Section 1291 of the Code discussed above with respect to its common shares. However, a U.S. Holder that makes a QEF Election will be subject to U.S. federal income tax on such U.S. Holder’s pro rata share of (a) the net capital gain of the Company, which will be taxed as long-term capital gain to such U.S. Holder, and (b) the ordinary earnings of the Company, which will be taxed as ordinary income to such U.S. Holder. Generally, “net capital gain” is the excess of (a) net long-term capital gain over (b) net short-term capital gain, and “ordinary earnings” are the excess of (a) “earnings and profits” over (b) net capital gain. A U.S. Holder that makes a QEF Election will be subject to U.S. federal income tax on such amounts for each tax year in which the Company is a PFIC, regardless of whether such amounts are actually distributed to such U.S. Holder by the Company. However, a U.S. Holder that makes a QEF Election may, subject to certain limitations, elect to defer payment of current U.S. federal income tax on such amounts, subject to an interest charge. If such U.S. Holder is not a corporation, any such interest paid will be treated as “personal interest”, which is not deductible.
A U.S. Holder that makes a QEF Election generally (a) may receive a tax-free distribution from the Company to the extent that such distribution represents “earnings and profits” of the Company that were previously included in income by the U.S. Holder because of such QEF Election and (b) will adjust such U.S. Holder’s tax basis in the common shares to reflect the amount included in income or allowed as a tax-free distribution because of such QEF Election. In addition, a U.S. Holder that makes a QEF Election generally will recognize capital gain or loss on the sale or other taxable disposition of common shares.
The procedure for making a QEF Election, and the U.S. federal income tax consequences of making a QEF Election, will depend on whether such QEF Election is timely. A QEF Election will be treated as “timely” if it is made for the first year in the U.S. Holder’s holding period for the common shares in which the Company was a PFIC. A U.S. Holder may make a timely QEF Election by filing the appropriate QEF Election documents at the time such U.S. Holder files a U.S. federal income tax return for such year.
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A QEF Election will apply to the tax year for which such QEF Election is made and to all subsequent tax years, unless such QEF Election is invalidated or terminated or the IRS consents to revocation of such QEF Election. If a U.S. Holder makes a QEF Election and, in a subsequent tax year, the Company ceases to be a PFIC, the QEF Election will remain in effect (although it will not be applicable) during those tax years in which the Company is not a PFIC. Accordingly, if the Company becomes a PFIC in a subsequent tax year, the QEF Election will be effective, and the U.S. Holder will be subject to the QEF rules described above during a subsequent tax year in which the Company qualifies as a PFIC.
The Company intends to make available to U.S. Holders, upon their written request, all information and documentation that a U.S. Holder making a QEF Election with respect to the Company is required to obtain for U.S. federal income tax purposes. Such information may be included on the Company’s website. However, U.S. Holders should be aware that the Company can provide no assurances that it will provide any such information relating to any Subsidiary PFIC. Because the Company may own shares in one or more Subsidiary PFICs and may acquire shares in one or more Subsidiary PFICs in the future, U.S. Holders will continue to be subject to the rules discussed above with respect to the taxation of gains and excess distributions with respect to any Subsidiary PFIC for which the U.S. Holders do not obtain the required information to file a QEF Election. U.S. Holders should consult their own tax advisor regarding the availability of, and procedure for making, a QEF Election with respect to the Company and any Subsidiary PFIC.
Mark-to-Market Election
A U.S. Holder may make a Mark-to-Market Election only if the common shares are “marketable stock” as defined in Section 1296(e). The common shares generally will be “marketable stock” if they are regularly traded on (a) a national securities exchange that is registered with the SEC; (b) the national market system established pursuant to section 11A of the Securities and Exchange Act of 1934; or (c) a foreign securities exchange that is regulated or supervised by a governmental authority of the country in which the market is located, provided that (i) such foreign exchange has trading volume, listing, financial disclosure and other requirements and the laws of the country in which such foreign exchange is located, together with the rules of such foreign exchange, ensure that such requirements are actually enforced; and (ii) the rules of such foreign exchange ensure active trading of listed shares. If such shares are traded on such a qualified exchange or other market, such shares generally will be “regularly traded” for any calendar year during which such shares are traded, other than in de minimis quantities, on at least 15 days during each calendar quarter. Each U.S. Holder should consult its own tax advisor regarding whether the common shares constitute marketable stock.
A U.S. Holder that makes a Mark-to-Market Election with respect to its common shares generally will not be subject to the rules of Section 1291 of the Code discussed above. However, if a U.S. Holder does not make a Mark-to-Market Election beginning in the first tax year of such U.S. Holder’s holding period for common shares or such U.S. Holder has not made a timely QEF Election, the rules of Section 1291 of the Code discussed above will apply to certain dispositions of, and distributions on, the common shares.
A U.S. Holder that makes a Mark-to-Market Election will include in ordinary income, for each tax year in which the Company is a PFIC, an amount equal to the excess, if any, of (a) the fair market value of the common shares, as of the close of such tax year over (b) such U.S. Holder’s tax basis in such common shares. A U.S. Holder that makes a Mark-to-Market Election will be allowed a deduction in an amount equal to the excess, if any, of (i) such U.S. Holder’s adjusted tax basis in the common shares over (ii) the fair market value of such common shares (but only to the extent of the net amount of previously included income as a result of the Mark-to-Market Election for prior tax years).
U.S. Holders that make a Mark-to-Market Election generally also will adjust their tax basis in the common shares to reflect the amount included in gross income or allowed as a deduction because of such Mark-to-Market Election. In addition, upon a sale or other taxable disposition of common shares, a U.S. Holder that makes a Mark-to-Market Election will recognize ordinary income or loss (not to exceed the excess, if any, of (a) the amount included in ordinary income because of such Mark-to-Market Election for prior tax years over (b) the amount allowed as a deduction because of such Mark-to-Market Election for prior tax years).
A Mark-to-Market Election applies to the tax year in which such Mark-to-Market Election is made and to each subsequent tax year, unless the common shares cease to be “marketable stock” or the IRS consents to revocation of such election. U.S. Holders should consult their own tax advisors regarding the availability of, and procedure for making, a Mark-to-Market Election.
Although a U.S. Holder may be eligible to make a Mark-to-Market Election with respect to common shares, no such election may be made with respect to the shares of any Subsidiary PFIC that a U.S. Holder is treated as owning because such shares are not “marketable stock”. Hence, the Mark-to-Market Election will not be effective to eliminate the interest
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charge described above with respect to deemed dispositions of Subsidiary PFIC shares or distributions from a Subsidiary PFIC.
Other PFIC Rules
Under Section 1291(f) of the Code, the IRS has issued proposed Treasury Regulations that, subject to certain exceptions, would cause a U.S. Holder that had not made a timely QEF Election to recognize gain (but not loss) upon certain transfers of common shares that would otherwise be tax-deferred (e.g., gifts and exchanges pursuant to corporate reorganizations) in the event the Company is a PFIC during such U.S. Holder’s holding period for the relevant shares. However, the specific U.S. federal income tax consequences to a U.S. Holder may vary based on the manner in which common shares are transferred.
Certain additional adverse rules will apply with respect to a U.S. Holder if the Company is a PFIC, regardless of whether such U.S. Holder makes a QEF Election. For example, under Section 1298(b)(6) of the Code, a U.S. Holder that uses common shares as security for a loan will, except as may be provided in Treasury Regulations, be treated as having made a taxable disposition of such common shares.
In any year in which the Company is classified as a PFIC, a U.S. Holder will be required to file an annual report with the IRS containing such information as Treasury Regulations and/or other IRS guidance may require. U.S. Holders should consult their own tax advisors regarding the requirements of filing such information returns under these rules, including the requirement to file an IRS Form 8621.
In addition, a U.S. Holder who acquires common shares from a decedent will not receive a “step up” in tax basis of such common shares to fair market value unless such decedent had a timely and effective QEF Election in place.
Special rules also apply to the amount of foreign tax credit that a U.S. Holder may claim on a distribution from a PFIC.
The PFIC rules are complex, and U.S. Holders should consult their own tax advisors regarding the PFIC rules and how they may affect the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares in the event the Company is a PFIC at any time during such holding period for such common shares.
Additional Considerations
Receipt of Foreign Currency
The amount of any distribution paid in foreign currency to a U.S. Holder in connection with the ownership of common shares, or on the sale, exchange or other taxable disposition of common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt or, if applicable, the date of settlement if the common shares are traded on an established securities market (regardless of whether such foreign currency is converted into U.S. dollars at that time). If the foreign currency received is not converted into U.S. dollars on the date of receipt, a U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt. A U.S. Holder that receives foreign currency and converts such foreign currency into U.S. dollars at a conversion rate other than the rate in effect on the date of receipt may have a foreign currency exchange gain or loss, which generally would be treated as U.S. source ordinary income or loss for foreign tax credit purposes. Different rules apply to U.S. Holders who use the accrual method of tax accounting. U.S. Holders should consult their own U.S. tax advisors regarding the U.S. federal income tax consequences of receiving, owning and disposing of foreign currency.
Foreign Tax Credit
Dividends paid on the common shares will be treated as foreign-source income, and generally will be treated as “passive category income” or “general category income” for U.S. foreign tax credit purposes. Any gain or loss recognized on a sale or other disposition of common shares generally will be United States source gain or loss. Certain U.S. Holders that are eligible for the benefits of the Canada - US Tax Treaty may elect to treat such gain or loss as Canadian source gain or loss for U.S. foreign tax credit purposes. The Code applies various complex limitations on the amount of foreign taxes that may be claimed as a credit by U.S. taxpayers. In addition, Treasury Regulations that apply to foreign taxes paid or accrued (the “Foreign Tax Credit Regulations”) impose additional requirements for Canadian withholding taxes to be eligible for a foreign tax credit, and there can be no assurance that those requirements will be satisfied. The Treasury Department has released guidance temporarily pausing the application of certain of the Foreign Tax Credit Regulations.
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Subject to the PFIC rules and the Foreign Tax Credit Regulations, each as discussed above, a U.S. Holder that pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on the common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax. Generally, a credit will reduce a U.S. Holder's U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder's income that is subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year. The foreign tax credit rules are complex and involve the application of rules that depend on a U.S. Holder’s particular circumstances. Accordingly, each U.S. Holder should consult its own U.S. tax advisor regarding the foreign tax credit rules.
Information Reporting, Backup Withholding Tax
Under U.S. federal income tax law and Treasury Regulations, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. For example, U.S. return disclosure obligations (and related penalties) are imposed on individuals who are U.S. Holders that hold certain specified foreign financial assets in excess of certain threshold amounts. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any shares or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a non-U.S. entity. U.S. Holders may be subject to these reporting requirements unless their common shares are held in an account at certain financial institutions. Penalties for failure to file certain of these information returns are substantial. U.S. Holders should consult their own tax advisors regarding the requirements of filing information returns, including the requirement to file an IRS Form 8938.
Payments made within the U.S. or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of common shares will generally be subject to information reporting and backup withholding tax if a U.S. Holder (a) fails to furnish such U.S. Holder’s correct U.S. taxpayer identification number (generally on IRS Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax. However, certain exempt persons generally are excluded from these information reporting and backup withholding rules. Backup withholding is not an additional tax. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner.
The discussion of reporting requirements set forth above is not intended to constitute a complete description of all reporting requirements that may apply to a U.S. Holder. A failure to satisfy certain reporting requirements may result in an extension of the time period during which the IRS can assess a tax, and under certain circumstances, such an extension may apply to assessments of amounts unrelated to any unsatisfied reporting requirement. Each U.S. Holder should consult its own tax advisors regarding the information reporting and backup withholding rules.
THE ABOVE SUMMARY IS NOT INTENDED TO CONSTITUTE A COMPLETE ANALYSIS OF ALL TAX CONSIDERATIONS APPLICABLE TO U.S. HOLDERS WITH RESPECT TO THE ACQUISITION, OWNERSHIP AND DISPOSITION OF COMMON SHARES. U.S. HOLDERS SHOULD CONSULT THEIR OWN TAX ADVISORS AS TO THE TAX CONSIDERATIONS APPLICABLE TO THEM IN LIGHT OF THEIR OWN PARTICULAR CIRCUMSTANCES.
Exchange Controls
There are no governmental laws, decrees or regulations in Canada that restrict the export or import of capital, including foreign exchange controls, or that affect the remittance of dividends, interest or other payments to nonresident holders of the securities of Energy Fuels, other than Canadian withholding tax. See “Certain Canadian Federal Income Tax Considerations for Non-Residents of Canada,” below.
Certain Canadian Federal Income Tax Considerations for Non-Residents of Canada
The following is, as of the date hereof, a summary of the principal Canadian federal income tax considerations generally applicable under the Income Tax Act (Canada) and the regulations promulgated thereunder (the “Tax Act”) to a holder who acquires, as beneficial owner, our common shares, and who, for purposes of the Tax Act and at all relevant times: (i) holds the common shares as capital property; (ii) deals at arm’s length with, and is not affiliated with, us; (iii) is not, has not
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been, and will not be or deemed to be, resident in Canada; (iv) is not a “foreign affiliate” (as defined in the Tax Act) of a person resident in Canada; (v) has not entered into a “dividend rental arrangement”, a “derivative forward agreement” or a “synthetic disposition arrangement” (as such terms are defined in the Tax Act) in respect of our common shares; and (vi) does not use or hold and will not be deemed to use or hold, our common shares in a business carried on in Canada (a “Non-Resident Holder”). Generally, our common shares will be considered to be capital property to a Non-Resident Holder provided the Non-Resident Holder does not hold our common shares in the course of carrying on a business of trading or dealing in securities and has not acquired them in one or more transactions considered to be an adventure or concern in the nature of trade.
Special rules, which are not discussed in this summary, may apply to a Non-Resident Holder that is an insurer that carries on an insurance business in Canada and elsewhere or is an authorized foreign bank (as defined in the Tax Act). Such Non-
Resident Holders should seek advice from their own tax advisors.
This summary is based upon the provisions of the Tax Act in force as of the date hereof, all specific proposals to amend the Tax Act that have been publicly and officially announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (the “Proposed Amendments”) and management’s understanding of the current administrative policies and assessing practices of the Canada Revenue Agency (the “CRA”) published in writing by it prior to the date hereof. This summary assumes the Proposed Amendments will be enacted in the form proposed. However, no assurance can be given that the Proposed Amendments will be enacted in their current form, or at all. This summary is not exhaustive of all possible Canadian federal income tax considerations and, except for the Proposed Amendments, does not take into account or anticipate any changes in the law or any changes in the CRA’s administrative policies or practices, whether by legislative, governmental, or judicial action or decision, nor does it take into account or anticipate any other federal or any provincial, territorial or foreign tax considerations, which may differ significantly from those discussed here.
Non-Resident Holders should consult their own tax advisors with respect to an investment in our common shares. This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any prospective purchaser or holder of our common shares, and no representations with respect to the income tax consequences to any prospective purchaser or holder are made. Consequently, prospective purchasers or holders of our common shares should consult their own tax advisors with respect to their particular circumstances.
Item 6. [Reserved]
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is a discussion and analysis of the Company’s financial condition and historical results of operations. The following should be read in conjunction with our financial statements and accompanying notes. This discussion contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results could differ materially from those projected, forecasted or expected in these forward-looking statements as a result of various factors, including but not limited to, those discussed below and elsewhere in this Annual Report. Refer to “Cautionary Note Regarding Forward-looking Statements” and Item 1A. Risk Factors herein. Our management believes the assumptions underlying the Company’s financial statements and accompanying notes are reasonable. However, the Company’s financial statements and accompanying notes may not be an indication of our financial condition and results of operations in the future.
Business Overview
enCore Energy Corp., America’s Clean Energy Company™, was incorporated on October 30, 2009, under the Laws of British Columbia and is a reporting issuer in all of the provinces and territories of Canada. As of January 1, 2025, the Company ceased to be a “foreign private issuer” and has become a “domestic issuer” and a non-accelerated filer within the meanings under the Exchange Act. As a result, the Company must comply with the filing deadlines and disclosure obligations of a domestic issuer and non-accelerated filer as set forth in the Exchange Act. This classification impacts the timing of our periodic filings, internal control assessments, and other regulatory requirements. The Company’s common shares are listed on Nasdaq and the TSX-V under the trading symbol EU.
We are an Exploration Stage Issuer as defined by S-K 1300 as we have not established proven or probable mineral reserves, through the completion of a pre-feasibility or feasibility study for any of our uranium projects, as required by the SEC to be defined as a Development Stage Issuer. Even though we commenced extraction of uranium at our Rosita Project and our Alta Mesa Project, the Company remains classified as an Exploration Stage Issuer and will continue to remain an Exploration Stage Issuer until such time as proven or probable mineral reserves have been established at one of our uranium projects.
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The Company is focused on extracting domestic uranium within the United States. The Company utilizes only proven ISR technology to provide necessary fuel for the generation of clean, reliable, and carbon-free nuclear energy. In 2023, the Company commenced uranium extraction at the Rosita CPPs and at the Alta Mesa CPP in South Texas. enCore’s strategy is to build uranium extraction capacity by developing and placing into operation a series of uranium extraction facilities in South Texas, followed by a future pipeline of exploration projects in South Dakota and Wyoming, becoming a leading supplier of domestic uranium to fuel a growing demand for clean energy generation using nuclear power.
Industry and Market Update
The primary use of uranium is to fuel nuclear power plants for the generation of carbon and emission free electricity. According to the World Nuclear Association (“WNA”), as of September 2025, there were 440 operable nuclear reactors world-wide, which required approximately 180 to 225 million pounds of U 3 O 8 annually at full operation. According to data from TradeTech LLC (“TradeTech”), the world continues to require more uranium than it produces from primary extraction. The gap between demand and primary supply is being filled by stockpiled inventories and secondary supplies, which the Company believes have dwindled significantly in recent years.
Expanding the current reactor fleet to meet the levels of electrical generating capacity remains a significant challenge to the nuclear industry. To meet those goals, the global industry must protect existing capacity, and there have been multiple public pronouncements from several countries, including the United States to protect existing nuclear generating capacity. In the United States, as a result of clean energy credits granted by several states and the production tax credit for nuclear power provided in the Inflation Reduction Act of 2022, several nuclear utilities have announced operating life extensions and capacity expansions within their existing operating fleet. Also, the industry has seen an unprecedented trend in reactor recommissioning. In the United States, where just a few years ago reactors were being shut down prematurely, nuclear plants such as Diablo Canyon, Palisades, Three Mile Island, and Duane Arnold are positioned to re-enter service.
With increasing demand expectations, an increase in uranium production must occur in an environment beset by risks, including import bans, sanctions, and secondary sanctions imposed by various countries, transportation issues, trade restrictions in other goods and services beyond nuclear fuel, and fewer available ports, all of which have combined to create widespread uncertainty in the market regarding the availability of both current and future supply.
On January 20, 2025, President Trump issued two Executive Orders that specifically referenced nuclear power and uranium as key parts to expanding energy production in the United States. The Executive Order titled, “Unleashing American Energy,” in addition to directing federal agencies to advance permitting for energy projects also called for uranium to be designated as a “critical mineral” by the U.S. Geological Survey. The Executive Order titled, “Declaring a National Energy Emergency,” directs federal agencies, under emergency authority, to advance permit and license approvals for the production of energy and energy resources. In that Executive Order, uranium is defined as an “energy resource” and subject to the emergency declaration. The U.S. Senate, on February 3, 2025, confirmed Chris Wright, former CEO of Denver-based Liberty Energy, to serve as Energy Secretary. The following day, Wright issued his first Secretarial Order, which directs the Department of Energy (“DOE”) to take immediate action to unleash energy produced in the U.S. in accordance with President Trump’s executive orders. See updates below related to President Trump’s Executive Orders.
Below is a list of some of the recent government policy, U.S. market and global market news that can influence the uranium market.
U.S. Government Policy News
•U.S. Senate Majority Leader John Thune (Republican - South Dakota) is reportedly prepared to schedule a vote on a previously postponed Russia sanctions measure. The legislation, the Sanctioning Russia Act of 2025 (S. 1241), was introduced in April by Senators Lindsey Graham (Republican-South Carolina) and Richard Blumenthal (Democrat - Connecticut) and currently has the support of 84 additional senators. A companion measure in the House of Representatives has garnered backing from more than 100 members.
•U.S. Senators Ted Cruz (Republican – Texas) and Martin Heinrich (Democrat – New Mexico) introduced the Advancing Research in Nuclear Fuel Recycling Act of in October 2025. The proposed legislation would direct the United States DOE to conduct a comprehensive study evaluating the costs, benefits, and risks associated with recycling the nation’s spent nuclear fuel, with particular emphasis on comparisons to interim storage alternatives.
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•Westinghouse Electric Company, Cameco Corporation, and Brookfield Asset Management have announced that the U.S. Government has entered into a strategic partnership to accelerate the deployment of nuclear power pursuant to Executive Orders issued by President Donald Trump on May 23, 2025. The initiative is expected to be supported by at least by an $80 billion investment for the construction of new nuclear reactors across the United States, utilizing Westinghouse reactor technology. Under the terms of the partnership, the U.S. Government will be granted a participation interest that, upon vesting, would entitle it to receive 20 percent of certain cash distributions made by Westinghouse, in excess of $17.5 billion, following the granting of the participation interest. Vesting is contingent upon the U.S. Government making a final investment decision and entering into definitive agreements for the construction of new Westinghouse nuclear reactors in the United States.
•On November 18, 2025, the U.S. Secretary of Energy, Chris Wright and the Kingdom of Saudi Arabia’s Minister of Energy, Prince Abdulaziz bin Salman Al Saud, signed a Joint Declaration confirming the completion of negotiations on civil nuclear cooperation. The declaration established a legal foundation for expanded civil nuclear cooperation between the two countries and signaled the intent for a long-term, multi-billion-dollar partnership in civil nuclear energy, which may include development, deployment, and technology collaboration involving U.S. companies.
•The U.S. Army has identified nine military installations as potential sites for microreactor power plants under its Janus Program, a next-generation nuclear power initiative aimed at enhancing energy resilience. The program envisions the deployment of commercially built microreactors at selected bases across the United States.
•The U.S. DOE has selected the TVA and Holtec Government Services to support the early deployment of advanced light-water SMRs in the United States. The selected project teams are eligible to receive up to $800 million in federal cost-shared funding to advance initial SMR projects in Tennessee and Michigan.
•U.S. Secretary of Energy Chris Wright noted in September 2025, that the United States should consider expanding its strategic uranium reserve, emphasizing the importance of securing long-term uranium supplies to support the nation’s nuclear energy program. During the quarter ended December 31, 2025, the DOE issued funding opportunities and notices to accelerate domestic critical minerals and materials production, supporting technologies that underpin nuclear fuel supply chains and other strategic materials. In January 2026, DOE announced approximately $2.7 billion in contract awards to expand domestic uranium enrichment capacity for both low-enriched uranium (LEU) and high-assay low-enriched uranium (HALEU). This initiative supports development of a more secure U.S. nuclear fuel supply chain and complements strategic reserve discussions by enhancing production capabilities.
•Since March 30, 2025, the United States has implemented a series of aggressive tariff measures that have reshaped global trade relations. On March 24, President Trump issued Executive Order 14245, imposing a 25% tariff on all goods imported from countries that continue purchasing Venezuelan oil. This was followed by a broader escalation during what the administration termed “Liberation Day,” from April 2 to April 5. The United States enacted a sweeping 10% baseline tariff on nearly all imports, with reciprocal rates reaching as high as 34% on Chinese goods and 20–24% on products from the European Union and Japan. Steel and aluminum tariffs were also significantly increased during this period, rising to 50% globally. Legal challenges quickly followed: On May 28, 2025, the United States Court of International Trade ruled that the Liberation Day tariffs exceeded presidential authority under the International Emergency Economic Powers Act (IEEPA), issuing an injunction to block enforcement. Tariffs based on Section 232 (national security) and Section 301 (China-related trade practices) remain legally intact and enforceable as of December 31, 2025. The IEEPA tariffs also remains, thus collection continued until February 2026, when the Supreme Court ruled the tariffs were unconstitutional.
•President Trump signed an Executive Order on February 14, 2025, to establish the National Energy Dominance Council, which is chaired by the Secretary of Interior, Doug Burgum, and vice-chaired by Energy Secretary, Chris Wright. The council's members also include the Secretary of State, Secretary of the Treasury, Secretary of Defense, the Attorney General, Secretary of Agriculture, Secretary of Commerce, and Secretary of Transportation. The Council was expected to present President Trump with a plan for how to raise awareness of the American energy dominance plan within 100 days. As of December 31, 2025, the council has actively advanced its agenda with the following:
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•Encouragement for power plants to increase output by 10% to 15% to support rising electricity demand, especially from artificial intelligence systems.
•Advancing the reversal of the Biden era Liquefied Natural Gas (“LNG”) export clause. The reversal of the export clause has led to the approval of record levels of future U.S. LNG exports in an effort to position the U.S. as the leading LNG exporter in the world.
•The Council has also outlined the initiative to re-open closed power plants, expanding energy infrastructure, launching small modular nuclear reactors, and fast tracking mining/mineral projects.
The Council met during the year ended December 31, 2025, however, no public version of the meeting notes and/or strategy has been made available.
U.S. Market News
•X-Energy Reactor Company, LLC, a U.S. based developer of advanced nuclear reactor and fuel technologies, has announced a Series C-1 financing round totaling approximately $500 million, anchored by Amazon.com, Inc. The investment will support the completion of X-Energy’s reactor design and licensing activities, as well as fund the initial phase of its TRISO-X fuel fabrication facility in Oak Ridge, Tennessee, to help address growing energy demand.
•Global Laser Enrichment (“GLE”) has concluded an independent, third-party validation of its next-generation uranium enrichment technology, which confirms that the company has achieved Technology Readiness Level 6 following the completion of its large-scale enrichment demonstration program.
•California-based General Matter announced plans to build a privately developed facility to enrich uranium in the state of Kentucky. The company, which is backed by investor Peter Thiel, said it intends to make a “historic investment in American nuclear infrastructure” by restoring a shuttered facility in Paducah, Kentucky. General Matter was one of four companies selected in October 2024 by the DOE to provide enrichment services to help establish a U.S. supply of high-assay low-enriched uranium for advanced reactor designs.
•Uranium Energy Corporation launched the United States Uranium Refining and Conversion Corp., a wholly owned subsidiary that will engage in the feasibility of developing a new state-of-the-art American uranium refining and conversion facility.
•During the year ended December 31, 2025, NextEra Energy announced two agreements with Google, which will strengthen U.S. nuclear leadership and help meet growing energy demand from artificial intelligence (AI) with clean and reliable nuclear energy. The cornerstone of this collaboration is the planned restart of the Duane Arnold Energy Center, the only nuclear facility in the U.S. state of Iowa. The plant (615 MWe BWR), which was shut down in 2020, is expected to be fully operational by the first quarter of 2029, pending regulatory approvals to restart the plant.
•The New York Power Authority has issued its first solicitations as part of a new initiative to develop 1 GW of advanced nuclear energy.
•Crusoe, an artificial intelligence data center developer, has entered into a partnership with Blue Energy, a U.S. based nuclear energy company, to develop a nuclear-powered data center campus with up to 1.5 GW of capacity at the Port of Victoria in Victoria, Texas. The planned 1,600-acre campus is expected to begin receiving power as early as 2028, initially supplied by natural gas–fired generation, with a transition to nuclear energy targeted for completion by 2031.
•Constellation, a U.S. based energy company, announced that its Crane Clean Energy Center has secured a $1.0 billion loan from the DOE. This transaction marks the first instance in which the DOE Loan Programs Office has simultaneously finalized a conditional loan commitment and achieved financial close.
•Urenco USA has achieved two significant milestones at its uranium enrichment facility in New Mexico: the company’s first production of enriched uranium exceeding 5% U-235, and the startup of an additional centrifuge cascade as part of its ongoing capacity expansion program.
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•Four public electric utilities -Nebraska Public Power District, Omaha Public Power District, and Lincoln Electric System—together with the Grand River Dam Authority of Oklahoma, have jointly announced the execution of a Memorandum of Understanding to establish the Great Plains New Nuclear Consortium.
•Centrus Energy announced that it has commenced domestic centrifuge manufacturing to support commercial LEU enrichment operations at its facility in Piketon, Ohio.
•The state of Texas is moving toward the creation of a taxpayer funded nuclear power incentive fund. About 80% of the fund’s $350 million would be dedicated toward reimbursing construction costs for functional nuclear reactors. The remainder would be used for research and development. As of October 2025, several companies and projects have expressed interest in Texas’s $350 million nuclear incentive fund, established under House Bill 14. The fund is administered by the Texas Advanced Nuclear Energy Office, which was created to support the development of advanced nuclear reactors and associated industries in the state.
Global Market News
•Following a meeting with U.S. President Donald Trump, the Government of Japan announced its intention to provide up to $332 billion in support for critical energy projects in the United States, including investments in the development and construction of nuclear reactor projects.
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Sales of Uranium and Sales Agreements
During the year ended December 31, 2025, the Company completed uranium sales totaling 655,000 pounds of U 3 O 8, not including converter and transaction costs, for an average sales price of $65.89 per pound of U 3 O 8.
enCore’s uranium sales strategy provides a base level of projected income from sales contracts while preserving a significant ability to realize opportunities when strong short-term market fundamentals are present.
The Company has been able to use improving uranium market conditions to create a balanced uranium sales agreement portfolio, to provide multiple pricing structures to support future market changes and support production plans. As of December 31, 2025, we have executed fourteen uranium sales agreements to supply uranium to nuclear power plants in the United States and one legacy uranium sales agreement with a uranium trading company. enCore’s uranium sales agreement portfolio is a mix of market related pricing, hybrid base price and market related pricing, base escalated pricing, and fixed prices. Of enCore’s fourteen current uranium sales agreements, two are market-related with no floors or ceilings and eight are market related that typically retain exposure to spot pricing, while including minimum floor and maximum ceiling prices, some of which are adjusted upwards periodically for inflation. Minimum floor prices are set at levels that provide the Company with a comfortable margin over its expected costs of operations in Texas while still allowing the Company to participate in anticipated escalations of the price of uranium. The Company will continue to assess opportunities to secure future sales agreements that will support its continued project and production growth strategies. The Company is committed to honoring all sales commitments.
Corporate Updates for the Fourth Quarter 2025
•On October 14, 2025, the Company announced new uranium discoveries had been made in areas in or near existing wellfields. These discoveries were made as a result of a major ongoing re-analysis of thousands of historic drill holes from across the Alta Mesa Project that began in April 2025. This more granular and detailed evaluation has identified uranium mineralized roll fronts in at least three areas to date.
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Operations Update
The Company is focused on producing uranium in the United States and delivering that uranium to customers. The Company currently utilizes only the proven ISR technology to provide necessary fuel for the generation of clean, reliable, and carbon-free nuclear energy.
enCore owns 3 of the 10 licensed and constructed CPPs in the United States. The Company has several key mineral resource projects in other jurisdictions within the United States. Our S-K 1300 compliant resources are listed below:
Total measured and indicated mineral resources 30.94 million lbs U 3 O 8
Total inferred mineral resources 20.54 million lbs U 3 O 8
The Company’s strategy over the next three years is centered around two of its fully licensed Texas CPPs: Rosita and Alta Mesa. The CPPs located at the Rosita and Alta Mesa projects are designed for, and fully capable of, processing feed resin from relocatable satellite IX plants employed at various deposits within a 100-mile radius of each plant. The Rosita CPP was the starting point for enCore’s Texas extraction strategy. In 2024, the Company announced it had commenced uranium extraction operations at Rosita from the Rosita Extension wellfield, PAA-5. Rosita is located approximately 60 miles from Corpus Christi, Texas and has an 800,000-pound U 3 O 8 per year production capacity.
In February 2023, the Company acquired 100% of the Alta Mesa Uranium Project and the Mesteña Grande Uranium Project from Energy Fuels Inc., for $120 million. The Company’s fully licensed Alta Mesa CPP is located approximately 100 miles southwest of Corpus Christi, Texas, and has a production capacity of 1.5 million pounds of U 3 O 8 per year through its IX system located at the plant. The facility has elution, precipitation, drying, and packaging capacity for 2.0 million pounds of U 3 O 8 per year. This plant is designed to accept direct production feed to the IX columns in the plant and concurrently accept loaded resin from satellite locations, once the resin transfer system has been installed. The Alta Mesa Project includes existing and near-term production areas, including fully permitted and authorized production areas 6 and 7. The Mesteña Grande Uranium Project has additional inferred mineral resource areas that will require significant additional exploration drilling and permitting prior to being able to be brought online. In total, the Alta Mesa Uranium Project combined with the Mesteña Grande Uranium Project encompasses mineral leases on over 200,000 acres of private land. In February 2024, the Company sold a 30% interest in the Alta Mesa and Mesteña Grande projects to Boss for $60 million.
In June 2024, the Company announced the successful startup of uranium extraction operations at the Alta Mesa Project. With the restart of the previously operating Alta Mesa Project, the Company is now the only uranium producer in the United States with multiple production facilities in operation as of December 31, 2025. The initial ramp-up was a progressive process to advance and continue increased uranium extraction via direct feed to the Alta Mesa CPP. Exploration drilling and wellfield installation continues at PAA-7 and the second IX circuit at the Alta Mesa CPP was brought online in early 2025 and production continues through both IX circuits. During the year ended December 31, 2025, the head grade through the South train peaked at 110mg/L and averaged 38mg/L, and the West train peaked at 141mg/L for an average grade of 67mg/L. Additional production wells are being brought online regularly which has brought both processing trains to near maximum flow capacity. Utilizing the Pathcad software, the Company is able to adjust wellfield flow patterns to more optimally recover the mineralization and are adjusting patterns and flow to help improve wellfield performance.
During the year ended December 31, 2025, the Company announced new uranium discoveries made in areas in or near existing wellfields. These discoveries have been made as a result of a major ongoing re-analysis of thousands of historic drill holes that began in April 2025 across the Alta Mesa ISR Uranium Project. This more granular and detailed evaluation has identified uranium mineralized roll fronts in at least three areas to date. Follow up drilling by the Company has delineated these new roll fronts with drilling continuing to determine the extents of each.
This additional roll front uranium mineralization has been discovered in close proximity to known and already exploited roll fronts. One of these new roll fronts has progressed to the point that it has now advanced to permitting as a Wellfield 3 extension. Mineralized roll fronts have also been found overlying the past productive mineralization in Wellfield 4 with at least two new roll fronts discovered to date, each extending more than 2,500 feet in length with both included in the existing permit authorization. This newly discovered mineralization lies at a depth of 320 to 345 feet, almost 200 feet above the previously exploited roll front. This shallow mineralization makes for shorter drill times with less footage required, less cement and shorter casing intervals resulting in significant cost savings in delineation and extraction versus deeper mineralization. A third area extending south from the previously exploited mineralization in Wellfield 1 continues
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to expand with additional ongoing drilling. This granular re-analysis of previous drill data is continued through December 31, 2025, and follow-up delineation drilling is expected to continue into 2026.
The Kingsville Dome CPP is currently maintained in a standby condition and will require refurbishment prior to commencement of operations. This facility, similar in size and design to the Rosita CPP facility, has a capacity of 800,000 pounds of U 3 O 8 per year.
As the Company has been increasing its operational pace to meet our targets for uranium extraction rates, we have successfully increased our drill rig capacity to facilitate replacing mineral resource depletion and adding mineral resources in South Texas. The Company started with 6 active drill rigs in South Texas at the beginning of 2024, and by December 31, 2024, the number increased to 17. As of December 31, 2025, the Company had 30 active rigs in South Texas. The Company has an experienced technical team with years of experience in ISR operations in Texas, Wyoming, and Nebraska supporting and managing our operations. We have been able to utilize our experience to self-execute the refurbishment of the Rosita and Alta Mesa CPPs, along with the design, construction and installation of infrastructure for three wellfields and two satellite IX facilities over a period of three years.
South Texas Regulatory Proceedings
Each of the Company’s production facilities maintain several permits and licenses in order to manage the current operations. For the Company’s operating locations, permits and licenses remain current and in effect. In specific cases, some of those permits and licenses are in renewal, and for some expansion activities, new permits or amendments will be necessary. All of our South Texas facility ISR and underground injection operations are regulated by the TCEQ and the Radioactive Material Licenses (“RMLs”) for Rosita and Alta Mesa are issued by the TCEQ under the NRC Agreement State Program that assures that a mature and consistent regulatory process is in place to provide more certainty regarding regulatory approvals.
Currently, at Alta Mesa, the RML and the Class III UIC Area Permit are in timely renewal and under technical review by the TCEQ, but those do not affect current expansion activities. At Upper Spring Creek, the TCEQ has issued the Class III UIC Area Permit, and the agency has approved the expansion of the Rosita RML to incorporate the Upper Spring Creek wellfield and satellite IX facility into the current license activities. Construction of the satellite and wellfield at Upper Spring Creek has commenced. Remaining permits needed to begin operations are the Production Area Authorization and the Class I Waste Disposal Well permit, both of which are under review by the TCEQ as of December 31, 2025.
South Dakota Developments
In addition to the Company’s operations in South Texas, it is also developing pipeline projects in other states. The advanced stage Dewey-Burdock Uranium Project in South Dakota has demonstrated ISR resources, including a 2024 S-K 1300 Technical Report Summary and Canadian National Instrument 43-101 Technical Report and PEA citing robust economics. The project has its source material license from the NRC and its underground injection permits and aquifer exemption from the EPA. In April 2024, the Company submitted its application to renew the ten year old Source Material License, SUA-1600. The NRC has confirmed that the Dewey-Burdock Source Material License is in timely renewal. The underground injection permits were appealed to the EPA’s EAB and the aquifer exemption was appealed to the 8th Circuit Court of Appeals. On September 16, 2025, the Company announced that the EAB denied in full a petition for review filed by the Oglala Sioux Tribe, Black Hills Clean Water Alliance, and NDN Collective against the EPA’s issuance of Class III and Class V UIC permits for the Dewey Burdock Project in South Dakota. The decision allows the Dewey Burdock Project to advance through federal permitting with the commencement of state permitting activities in 2025, accelerating the Project towards development ahead of schedule.
In September of 2025, the Company announced the Dewey Burdock Project had been approved for inclusion in the Fast-41 Program by the U.S. Federal Permitting Improvement Steering Council (“Permitting Council”). This is a component of the implementation of President Trump’s Executive Order on Immediate Measures to Increase American Mineral Production. The Dewey-Burdock Project received its Source and Byproduct Materials License in 2014, from the NRC, now under timely renewal, and will work with the NRC as the lead agency for federal permitting. enCore’s objective is to advance the Dewey Burdock Project into development and operation utilizing the ISR uranium extraction process.
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Under the Executive Order, the Permitting Council identifies priority infrastructure and critical mineral projects to receive accelerated permitting review. The addition of the first South Dakota ISR project supports the domestic uranium production focus of the United States. This focus enables the development of essential clean energy, extracted through environmentally responsible ISR technology, to provide affordable, reliable domestic energy.
Wyoming Developments
The Company has commenced the initial permitting work to advance the Gas Hills Project as an ISR uranium recovery operation located in central Wyoming, approximately 60 miles west of Casper. As part of the initial data collection for project permitting, the Company initiated core drilling during 2024. Our Gas Hills Project is located in the historic Gas Hills Uranium District in the brownfield area of extensive previous extraction.
In 2024, we disclosed that the Company initiated exploration drilling on the Dewey Terrace Project area. The near term goal of this drilling is designed to not only define the extent of the Dewey Terrace project mineralization, but also determine its eastern extent and potential to connect with our Dewey-Burdock deposit just across the state line in South Dakota. The drilling at both the Gas Hills and the Dewey Terrace Projects remain ongoing.
Results of Operations:
The following table summarizes the results of operations for the years ended December 31, 2025, and 2024:

| Years Ended December 31 |  | Increase (Decrease) |  | Percent Change
(in thousands except per share data) | 2025 $ | 2024 $ |  |
Revenue | 43,155 |  | 58,334 |  |  | (15,179) |  |  | (26)%
Cost of sales | 33,463 |  | 65,541 |  |  | (32,078) |  |  | (49)%
Operating expenses, excluding stock option expense | 71,254 |  | 60,188 |  |  | 11,066 |  |  | 18%
Stock option expense | 4,203 |  | 4,788 |  |  | (585) |  |  | (12)%
Interest income | 1,715 |  | 2,476 |  |  | (761) |  |  | (31)%
Interest expense | (3,392) |  | (1,735) |  |  | (1,657) |  |  | 96%
Loss on marketable securities, unrealized | (5,681) |  | (2,711) |  |  | (2,970) |  |  | 110%
Gain on marketable securities, realized | 9,613 |  | 248 |  |  | 9,365 |  |  | 3,776%
Net loss before income taxes | (63,511) |  | (73,922) |  |  | 10,411 |  |  | (14)%
Basic and diluted loss per share(1) | $ | (0.30) |  | $ | (0.34) |  |  | 0.04 |  |  | (12)%

(1) For the years ended December 31, 2025 and 2024, outstanding stock options, warrants, unvested restricted stock units and the Convertible Senior Notes are excluded from the calculation of our diluted weighted average common shares outstanding as their effect would be anti-dilutive due to a net loss from continuing operations.
The following table sets forth selected operating data and financial metrics for uranium sales for the years ended December 31, 2025, and 2024.

| Year Ended December 31 |  | Increase (Decrease) |  | Percent Change
| 2025 |  | 2024
Volumes sold (lbs) | 655,000 |  |  | 720,000 |  |  | (65,000) |  |  | (9)%
Realized sales price ($/lb) | 65.89 |  |  | 81.02 |  |  | (15.13) |  |  | (19)%
Costs applicable to revenues ($/lb) | 51.09 |  |  | 91.03 |  |  | (39.94) |  |  | (44)%

•Revenue - Revenue from uranium sales for the years ended December 31, 2025, was $43,155 compared to revenue of $58,334 for the years ended December 31, 2024, a decrease of $15,179. The decrease is driven by less volumes sold and lower realized sales prices caused by ceiling prices embedded in contracts with customers. The realized sales prices per pound of uranium for the years ended December 31, 2025 and 2024 were $65.89 and $81.02, respectively, and included the contractual sales price less sales-related costs such as transfer fees. The realized sale price per pound decrease is dictated by the market for uranium, which is a commodity.
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•Cost of Sales - Costs applicable to uranium sales were $33,463 for the years ended December 31, 2025, related to the completed sale of 655,000 pounds of uranium at a weighted average cost of $51.09 per pound compared to uranium costs of $65,541 for the sale of 720,000 pounds at a weighted average cost of $91.03 per pound for the years ended December 31, 2024. The decrease in costs was the result of no purchases of uranium, offset by more sales placed on extracted uranium at a lower market price. The Company’s weighted average cost components include the cost of purchased uranium and uranium from extraction.
•Operating expenses - Operating expenses include selling, general and administrative expenses. Operating expenses, excluding stock option expenses, for the years ended December 31, 2025, were $71,254 as compared to $60,188 for the years ended December 31, 2024. This increase primarily reflects the growth and increased activity levels the Company experienced in 2025, which was driven primarily by the increased extraction of uranium at Alta Mesa and Rosita which commenced during the latter part of 2024, combined with increased professional fees related to the Convertible Senior Notes and increased staff costs.
•Stock option expense - Stock option expense decreased for the years ended December 31, 2025 at $4,203 compared to $4,788 for the same period in 2024. The decrease in stock option expense is driven by the issuance, exercise, expiration and forfeiture of issued options and common shares.
•Interest income - Interest income for the years ended December 31, 2025, and December 31, 2024, was $1,715 and $2,476, respectively. The decrease was primarily driven by the decrease in cash held in brokerage and bank accounts.
•Interest expense - Interest expense for the years ended December 31, 2025, and December 31, 2024, was $3,392 and $1,735, respectively. The increase is primarily driven by the interest expense related to the Convertible Senior Notes. See Note 1 5 - Debt for more information.
•Gain/(Loss) on marketable securities, unrealized - The Company recognized a loss of $5,681 on the fair value of marketable securities, unrealized for the years ended, December 31, 2025 compared to a loss of $2,711 for the years ended December 31, 2024. Unrealized gains and losses for the years ended December 31, 2025 and 2024, are due to favorable and unfavorable market conditions for the respective periods.
•Gain on marketable securities, realized - The Company recognized a gain of $9,613 on the fair value of marketable securities, realized for the years ended December 31, 2025, as a result of the sale of common share investments compared to a gain $248 for the years ended December 31, 2024.
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The table below presents total cost of extracted pounds and uranium costs per extracted pound during the reporting period. Total cost of extracted pounds is the cost of sales less the cost of sales of purchased goods, which includes the aggregate purchase price of uranium sourced from purchased uranium. Uranium cost per extracted pound is the total cost of extracted pounds divided by the pounds of uranium extracted during the period. Total cost of extracted pounds and uranium costs per extracted pound, includes the allocation of cash and non-cash costs
During the year ended December 31, 2025, the Company continued its uranium extraction activities at its South Texas operations.

Total Costs of U 3 O 8 Sold |  |  |  |  |  |  |  |
|  | Year Ended December 31, 2025 |  | Year Ended December 31, 2024
|  | Pounds U 3 O 8 | Cost ($000s) | Cost/Pounds |  | Pounds U 3 O 8 | Cost ($000s) | Cost/Pounds
Total Cost of Pounds |  | 655,000 | $33,463 | $51.09 |  | 720,000 | $65,541 | $91.03
Purchased (2024) inventory | (1) |  | 245,000 | $16,644 | $67.93 |  | 580,000 | $58,433 | $100.75
Extracted total cost |  | 410,000 | $16,819 | $41.02 |  | 140,000 | $7,108 | $35.99
Extracted: |  |  |  |  |  |  |  |
Cash costs | (2) |  |  | $11,804 | $28.79 |  |  | $6,304 | $31.40
Non-Cash costs | (3) |  |  | $5,015 | $12.23 |  |  | $804 | $4.59
(1) |  | Lower of actual cost or market price of the year ended December 31, 2025
(2) |  | Cash costs of extracted pounds related to cost of goods sold are a metric for investors in evaluating the Company’s operations.
(3) |  | Non-cash costs of extracted pounds related to cost of goods sold as an insight into additional expenses that impact overall costs and include

Inventory Remaining on Hand |  |  |  |  |  |  |
|  | As of December 31, 2025 |  | As of December 31, 2024
|  | Pounds U 3 O 8 | Cost ($000s) | Cost/Pounds |  | Pounds U 3 O 8 | Cost ($000s) | Cost/Pounds
Total Cost of Inventory |  | 132,013 |  | $5,317 | $40.28 |  | 358,408 |  | $20,967 | $58.50
Purchased (2024) inventory |  | - |  | $- | $- |  | 245,000 |  | $14,408 | $58.81
Extracted total cost |  | 132,013 |  | $5,317 | $40.28 |  | 113,408 |  | $6,559 | $57.84
Extracted: |  |  |  |  |  |  |  |
Cash costs | (1) |  |  | $4,605 | $34.88 |  |  | $4,883 | $43.06
Non-Cash costs | (2) |  |  | $713 | $5.40 |  |  | $1,676 | $14.78
(1) |  | Cash costs of extracted pounds related to cost of goods sold are a metric for investors in evaluating the Company's operations.
(2) |  | Non-cash costs of extracted pounds related to cost of goods sold as an insight into additional expenses that impact overall costs and include depletion and certain sales related fees.

The Company remains committed to cost efficiency and production optimization, ensuring competitive uranium extraction and processing. The Company anticipates further cost efficiencies as additional wellfield patterns come online and economies of scale improve.
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Liquidity and Capital Resources
Our short-term cash requirements are primarily driven by exploration and development activities aimed at advancing properties for uranium extraction. We expect to meet our short-term cash requirements generally through existing working capital. As of December 31, 2025, and December 31, 2024, the Company had cash and cash equivalents of $52,403 and $39,701, respectively, and working capital of $96,134 and $57,334, respectively.
Our long-term cash requirements are also primarily driven by exploration and development activities aimed at advancing properties for uranium extraction. We expect to meet our long-term cash requirements through various sources of capital, which may include a revolving credit facility or line of credit and future debt or equity issuances, existing working capital, and net cash provided by operations and property dispositions. However, there are a number of factors that may have a material adverse effect on our ability to access these capital sources, including the state of overall equity and credit markets, our degree of leverage, our unencumbered asset base and borrowing restrictions imposed by lenders (including as a result of any failure to comply with financial covenants in future indebtedness), general market conditions for uranium mining companies and other energy companies, our operating performance and liquidity and market perceptions about us. The success of our business strategy will depend, in part, on our ability to access these various capital sources.
On August 22, 2025, we issued $115,000 aggregate principal amount of Convertible Senior Notes. The Convertible Senior Notes bear an annual interest of 5.5%, payable semiannually in arrears and the Notes mature on August 15, 2030.
We believe that our available cash, expected operating cash flows, and future revolving credit facility or line of credit or equity or debt financings will provide sufficient funds for our operations and anticipated scheduled debt service payments for the next twelve-month period following December 31, 2025. We believe that our sources of long-term cash will be sufficient for our needs thereafter.
Cash Flows
The following table reflects cash flow activities for the year ended December 31, 2025 and 2024:

| Year Ended December 31,
| 2025 |  | 2024 |  | Increase (Decrease)
Net cash used in operating activities | $ | (24,992) |  |  | $ | (45,204) |  |  | $ | (20,212) |
Net cash used in investing activities | (46,224) |  |  | (29,990) |  |  | 16,234 |
Net cash provided by financing activities | 84,740 |  |  | 107,417 |  |  | (22,677) |
Impact of currency rate changes in cash | (185) |  |  | 56 |  |  | (241) |
Net increase in cash, cash equivalents and restricted cash | $ | 13,339 |  |  | $ | 32,279 |  |  | $ | (18,940) |

Net Cash Used in Operating Activities
Net cash used in operating activities decreased by $20,212, to cash used in operating activities of $24,992, for the year ended December 31, 2025, compared to cash used in operating activities of $45,204 for the year ended December 31, 2024. This is largely driven by paying off the note payable to a related party in 2025, as discussed in Note 15, offset by less purchases of uranium inventory during the year ended December 31, 2025, compared to the year ended December 31, 2024.
Net Cash Used In Investing Activities
Net cash used in investing activities increased by $16,234, to $46,224, for the year ended December 31, 2025, compared to $29,990 for the year ended December 31, 2024. This was largely driven by the purchase of marketable securities and the acquisition of property and equipment during the year ended December 31, 2025, compared to the same period in 2024.
Net Cash Provided by Financing Activities
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Net cash provided by financing activities decreased by $22,677, to $84,740 for the year ended December 31, 2025, compared to cash provided by financing activities of $107,417 for the year ended December 31, 2024. This was largely driven by the proceeds from the Convertible Senior Notes offset by a reduction in equity financing and, payment of capped call premiums. During the year ended December 31, 2024, the Company received proceeds from the sale of minority interest to Boss, exercised warrants and received proceeds from the private placement (see Note 13 - Stockholders’ Equity).
Commitments
The Company’s sales commitments, for all sales contracts, are presented in pounds (in thousands) below.

Year |  | Volume (in pounds)
2026 |  | 900
2027 |  | 850
2028 |  | 1,000
2029 |  | 1,500
2030 |  | 1,200
Thereafter |  | 2,500
Total |  | 7,950

Off Balance Sheet Arrangements
As of December 31, 2025, the Company had no material off-balance sheet arrangements such as guarantee contracts, contingent interest in assets transferred to an entity, derivative instruments obligations or any obligations that trigger financing, liquidity, market or credit risk to the Company.
Critical Accounting Policies and Estimates
Our consolidated financial statements have been prepared in accordance with U.S. GAAP. Preparation of the financial statements requires us to make judgments, estimates and assumptions that impact the reported amount of net sales and expenses, assets and liabilities and the disclosure of contingent assets and liabilities. We consider an accounting judgment, estimate or assumption to be critical when the estimate or assumption is complex in nature or requires a high degree of judgment and when the use of different judgments, estimates and assumptions could have a material impact on our consolidated financial statements. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Our significant accounting policies are described in more detail in Note 2 – Summary of Significant Accounting Policies of our Consolidated Financial Statements.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
Our exposure to market risks includes, but is not limited to, equity price risk, uranium price risk and foreign currency risk.
Equity Price Risk
We are subject to market risk related to the market price of our common shares, which trade on Nasdaq and TSX-V. Historically, we have relied upon equity financing from the sale of our common shares or securities convertible into our common shares to fund our operations. Movements in the price of our common shares have been volatile in the past and may continue to be volatile in the future. As a result, there is a risk that we may not be able to complete an equity financing at an acceptable price when required.
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In addition, we have investments in equity securities, which are common shares and warrants of publicly listed companies. Movements in the price of these equity securities have been volatile in the past and may continue to be volatile in the future.
Uranium Price Risk
We are subject to market risk related to the market price of uranium. As of December 31, 2025, we had no uranium supply or off-take agreements in place. Since future sales of uranium concentrates are contracted based on both spot and fixed pricing, fluctuations in the market price of uranium would have a direct impact on our revenues, results of operations and cash flows. We do not use derivative financial instruments for spec ulative trading purposes, nor do we hedge our uranium price exposure to manage our uranium price risk.
Foreign Currency Risk
We are subject to market risk related to foreign currency exchange rate fluctuations. Our functional currency is the United States Dollar; however, a portion of our business is transacted in other currencies including the Canadian Dollar. To date, these fluctuations have not had a material impact on our results of operations.
We do not use derivative financial instruments for speculative trading purposes, nor do we hedge our foreign currency exposure to manage our foreign currency fluctuation risk.
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Item 8. Financial Statements and Supplementary Data
Index to Financial Statements

Financial Statements | Page
Report of Registered Public Accounting Firm (KPMG PCAOB ID: 185) | F-2
Consolidated Balance Sheets as of December 31, 2025 and 2024 | F-4
Consolidated Statements of Operations for the Years Ended December 31, 2025 and 2024 | F-5
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2025 and 2024 | F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025 and 2024 | F-7
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2025 and 2024 | F-10
Notes to Consolidated Financial Statements | F-12

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Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
enCore Energy Corp:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of enCore Energy Corporation and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the c ritical audit matter or on the accounts or disclosures to which it relates.
Asset Retirement Obligation Costs
As discussed in Note 9 to the consolidated financial statements, the Company recorded an asset retirement obligation (ARO) liability of $18.9 million as of December 31, 2025. Asset retirement obligations consist of estimated final well closure, plant and equipment decommissioning and removal, and environmental remediation costs to be incurred by the Company in the future. The asset retirement obligation is estimated based on the current costs adjusted for inflation and then discounted at a credit adjusted risk-free rate.
We identified the evaluation of the future costs for asset retirement obligations as a critical audit matter. Specialized skills and knowledge were required to evaluate the Company’s determination of asset retirement obligations and their related costs to satisfy the ARO.
The following are the primary procedures we performed to address this critical audit matter. We tested the determination of the planned asset retirement obligations used in the estimate by inquiring of management and inspecting cost calculations included in applications approved and permitted by regulatory agencies. We involved environmental professionals with specialized skills and knowledge, who assisted in evaluating the Company’s planned asset retirement obligations for certain sites, including comparing the Company’s planned asset retirement obligations to those communicated to regulatory authorities.
/s/ KPMG LLP
We have served as the Company’s auditor since 2024.
Houston, Texas
March 31, 2026
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enCore Energy Corp
Consolidated Balance Sheets

| December 31,
(in thousands, except per share data) | 2025 |  | 2024
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 52,403 |  |  | $ | 39,701 |
Accounts receivable | 4,944 |  |  | - |
Prepaid expenses and other current assets | 3,559 |  |  | 2,700 |
Marketable securities | 43,591 |  |  | 24,046 |
Inventory, net | 5,317 |  |  | 20,967 |
Total current assets | 109,814 |  |  | 87,414 |
Mineral rights and properties, net | 265,834 |  |  | 271,922 |
Property, plant and equipment, net | 41,160 |  |  | 24,017 |
Intangible assets, net | 1,465 |  |  | 471 |
Restricted cash | 8,388 |  |  | 7,751 |
Marketable securities, non-current | - |  |  | 837 |
Right of use assets - operating lease | 3,083 |  |  | 310 |
Other long-term assets | 678 |  |  | - |
Total assets | $ | 430,422 |  |  | $ | 392,722 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |
Current liabilities |  |  |
Accounts payable and accrued liabilities | $ | 12,434 |  |  | $ | 7,464 |
Accounts payable - related parties | 1,060 |  |  | 2,378 |
Note payable - related party | - |  |  | 20,108 |
Operating lease liabilities, current | 186 |  |  | 130 |
Total current liabilities | 13,680 |  |  | 30,080 |
Deferred tax liabilities | 26,384 |  |  | 26,980 |
Asset retirement obligations | 18,915 |  |  | 16,918 |
Convertible senior notes | 109,986 |  |  | - |
Operating lease liabilities, non-current | 3,077 |  |  | 202 |
Total liabilities | 172,042 |  |  | 74,180 |
Commitments and contingencies (Note 10) |  |  |
Stockholders’ equity |  |  |
Common stock 187,354,424 and 186,114,948 shares issued and outstanding as of December 31, 2025 and December 31, 2024, respectively | 382,842 |  |  | 380,325 |
Additional paid-in-capital | 56,733 |  |  | 59,856 |
Accumulated deficit | (207,704) |  |  | (150,848) |
Accumulated other comprehensive loss | (2,626) |  |  | (3,597) |
Total stockholders' equity | 229,245 |  |  | 285,736 |
Non-controlling interests | 29,135 |  |  | 32,806 |
Total equity | 258,380 |  |  | 318,542 |
Total liabilities and stockholders' equity | $ | 430,422 |  |  | $ | 392,722 |

See accompanying notes to the consolidated financial statements.
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enCore Energy Corp
Consolidated Statements of Operations

| Years Ended December 31,
(in thousands, except share amounts) | 2025 |  | 2024
Revenue | $ | 43,155 |  |  | $ | 58,334 |
Cost of sales | 33,463 |  |  | 65,541 |
Gross profit (loss) | 9,692 |  |  | (7,207) |
Operating costs: |  |  |
Mineral property expenditures | 23,261 |  |  | 29,763 |
General and administrative | 42,613 |  |  | 27,056 |
Depreciation, amortization and accretion | 5,381 |  |  | 3,369 |
Other operating costs | 4,203 |  |  | 4,788 |
Total operating expenses | 75,458 |  |  | 64,976 |
Operating loss | (65,766) |  |  | (72,183) |
Gain on marketable securities, realized | 9,613 |  |  | 248 |
Loss on marketable securities, unrealized | (5,681) |  |  | (2,711) |
Interest income | 1,715 |  |  | 2,476 |
Interest expense | (3,392) |  |  | (1,735) |
Other expense | - |  |  | (17) |
Total other income (expense) | 2,255 |  |  | (1,739) |
Net loss before income taxes | (63,511) |  |  | (73,922) |
Income tax benefit | (488) |  |  | (5,929) |
Net loss | (63,023) |  |  | (67,993) |
Less: Net loss attributable to non-controlling interests | (6,167) |  |  | (6,601) |
Net loss attributable to enCore Energy Corp. | $ | (56,856) |  |  | $ | (61,392) |
Net loss per share basic | $ | (0.30) |  |  | $ | (0.34) |
Net loss per share diluted | $ | (0.30) |  |  | $ | (0.34) |
Weighted average number of shares |  |  |
Basic | 186,861,112 |  | 181,982,829
Diluted | 186,861,112 |  | 181,982,829

See accompanying notes to the consolidated financial statements.
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enCore Energy Corp
Consolidated Statements of Comprehensive Loss

| Years Ended December 31,
(in thousands) | 2025 |  | 2024
Net loss | $ | (63,023) |  |  | $ | (67,993) |
Other comprehensive gain (loss), (net of tax) |  |  |
Foreign currency translation adjustment | 971 |  |  | (1,805) |
Total other comprehensive gain (loss), (net of tax) | 971 |  |  | (1,805) |
Comprehensive loss | (62,052) |  |  | (69,798) |
Comprehensive loss attributable to non-controlling interests | (6,167) |  |  | (6,601) |
Comprehensive loss attributable to enCore Energy Corp. | $ | (55,885) |  |  | $ | (63,197) |

See accompanying notes to the consolidated financial statements.
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enCore Energy Corp
Consolidated Statements of Cash Flow

| Years Ended December 31,
(in thousands) | 2025 |  | 2024
OPERATING ACTIVITIES |  |  |
Net loss | $ | (63,023) |  |  | $ | (67,993) |
Adjustments to reconcile net loss to net cash used in operating activities |  |  |
Amortization, depreciation and accretion | 5,381 |  |  | 3,262 |
Amortization of debt issuance costs | 329 |  |  | - |
Depletion | 4,891 |  |  | 1,334 |
Stock based compensation | 4,203 |  |  | 4,788 |
Inventory impairment charge | 155 |  |  | 6,054 |
Asset retirement obligation (gain)/loss | (946) |  |  | 5,424 |
Exploration costs related to mineral properties | 11,595 |  |  | 9,392 |
Unrealized loss on marketable securities | 5,681 |  |  | 2,711 |
Deferred tax liability | (596) |  |  | (5,968) |
Realized gain on marketable securities | (9,613) |  |  | (248) |
Changes in operating assets and liabilities: |  |  |
Accounts receivables | (4,944) |  |  | - |
Prepaids and deposits | 8,466 |  |  | (10) |
Inventories | 11,107 |  |  | (7,575) |
Accounts payable and accrued liabilities | 4,450 |  |  | 4,079 |
Asset retirement obligations | (132) |  |  | (399) |
Due to related parties | (1,996) |  |  | (55) |
Net cash used in operating activities | $ | (24,992) |  |  | $ | (45,204) |
INVESTING ACTIVITIES |  |  |
Purchase of property, plant, and equipment | (19,997) |  |  | (11,348) |
Purchase of intangible assets | (1,000) |  |  | - |
Exploration costs related to mineral properties | (11,595) |  |  | (9,392) |
Purchase of marketable securities | (34,396) |  |  | (9,798) |
Proceeds from sale of marketable securities | 20,764 |  |  | 548 |
Net cash used in investing activities | $ | (46,224) |  |  | $ | (29,990) |
FINANCING ACTIVITIES |  |  |
Proceeds from issuance of convertible senior notes | 115,000 |  |  | - |
Payments of debt issuance costs | (5,343) |  |  | - |
Private placement proceeds | - |  |  | 10,000 |
Common stock issuance costs | - |  |  | (50) |
Proceeds from the At -the-Market ("ATM") sales | - |  |  | 2,008 |
Proceeds from exercise of warrants | 510 |  |  | 25,471 |
Proceeds from exercise of stock options | 1,062 |  |  | 1,760 |
Proceeds from sale of minority interest | - |  |  | 60,000 |
Contributions from non-controlling interest | 5,625 |  |  | 8,228 |
Payments on note payable - related party | (20,108) |  |  | - |
Payment of capped call premiums | (12,006) |  |  | - |
Net cash provided by financing activities | $ | 84,740 |  |  | $ | 107,417 |

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enCore Energy Corp
Consolidated Statements of Cash Flow (continued)

Net increase in cash, cash equivalents and restricted cash | 13,524 |  |  | 32,223 |
Foreign exchange difference on cash, cash equivalents and restricted cash | (185) |  |  | 56 |
Cash, cash equivalents and restricted cash, beginning of year | 47,452 |  |  | 15,173 |
Cash, cash equivalents and restricted cash, end of year | $ | 60,791 |  |  | $ | 47,452 |

See accompanying notes to the consolidated financial statements.
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enCore Energy Corp
Consolidated Statements of Cash Flow (continued)

| Years Ended December 31,
2025 |  | 2024
Supplemental disclosures: |  |  |
Cash paid for interest | $ | 2,328 |  |  | $ | - |
Non-cash activities: |  |  |
Property, plant, and equipment additions included in accounts payable and accrued liabilities | 678 |  |  | - |
Mineral property depletion costs capitalized into inventory during the period | 7,332 |  |  | 2,568 |
Inventory distributions to non-controlling interest | 6,829 |  |  | 1,905 |
Inventory received in exchange for note payable | - |  |  | 20,108 |
Conversion of promissory note, including equity portion, to shares | - |  |  | 23,117 |
Unpaid contributions from NCI | - |  |  | 1,759 |
Non-cash mineral property additions | 1,244 |  |  | - |

See accompanying notes to consolidated financial statements.
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enCore Energy Corp
Consolidated Statements of Stockholders’ Equity

| Common Stock |  |  |  | Equity Portion of Convertible Promissory Note |  | Additional Paid- in-Capital |  | Accumulated Deficit |  | Accumulated Other Comprehensive Loss |  | Noncontrolling Interests |  | Total Equity
(in thousands) | Shares |  | Amount |  |  |  |  |  |  |
Balance at January 1, 2024 | 165,133,798 |  | $ | 308,198 |  |  |  |  | $ | 3,813 |  |  | $ | 41,203 |  |  | $ | (89,456) |  |  | $ | (1,792) |  |  | $ | - |  |  | $ | 261,966 |
Net loss | - |  | - |  |  |  |  | - |  |  | - |  |  | (61,392) |  |  | - |  |  | (6,601) |  |  | (67,993) |
Private placement | 2,564,102 |  | 10,000 |  |  |  |  | - |  |  | - |  |  | - |  |  | - |  |  | - |  |  | 10,000 |
Contributions from non-controlling interest | - |  | - |  |  |  |  | - |  |  | 8,228 |  |  | - |  |  | - |  |  | 1,759 |  |  | 9,987 |
Inventory transfers to non-controlling interest | - |  | - |  |  |  |  | - |  |  | - |  |  | - |  |  | - |  |  | (1,905) |  |  | (1,905) |
Share issuance costs | - |  | (50) |  |  |  |  | - |  |  | - |  |  | - |  |  | - |  |  | - |  |  | (50) |
Shares issued for exercise of warrants | 8,781,985 |  | 33,373 |  |  |  |  | - |  |  | (7,902) |  |  | - |  |  | - |  |  | - |  |  | 25,471 |
Shares issued for exercise of stock options | 2,267,155 |  | 3,679 |  |  |  |  | - |  |  | (1,919) |  |  | - |  |  | - |  |  | - |  |  | 1,760 |
Shares issued for ATM | 495,765 |  | 2,008 |  |  |  |  | - |  |  | - |  |  | - |  |  | - |  |  | - |  |  | 2,008 |
Share-based compensation | - |  | - |  |  |  |  | - |  |  | 4,788 |  |  | - |  |  | - |  |  | - |  |  | 4,788 |
Conversion of convertible promissory notes to shares | 6,872,143 |  | 23,117 |  |  |  |  | (3,813) |  |  | - |  |  | - |  |  | - |  |  | - |  |  | 19,304 |
Non-controlling interest investment in JV Alta Mesa | - |  | - |  |  |  |  | - |  |  | 15,458 |  |  | - |  |  | - |  |  | 39,553 |  |  | 55,011 |
Cumulative translation adjustment | - |  | - |  |  |  |  | - |  | - |  |  | - |  |  | (1,805) |  |  | - |  |  | (1,805) |
Balance at December 31, 2024 | 186,114,948 |  | $ | 380,325 |  |  |  |  | $ | - |  |  | $ | 59,856 |  |  | $ | (150,848) |  |  | $ | (3,597) |  |  | $ | 32,806 |  |  | $ | 318,542 |
Balance at January 1, 2025 | 186,114,948 |  | $ | 380,325 |  |  |  |  | $ | - |  |  | $ | 59,856 |  |  | $ | (150,848) |  |  | $ | (3,597) |  |  | $ | 32,806 |  |  | $ | 318,542 |
Net loss | - |  | - |  |  |  |  | - |  |  | - |  |  | (56,856) |  |  | - |  |  | (6,167) |  |  | (63,023) |
Cash contributions from non-controlling interest | - |  | - |  |  |  |  | - |  |  | 5,625 |  |  | - |  |  | - |  |  | 9,325 |  |  | 14,950 |

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enCore Energy Corp
Consolidated Statements of Stockholders’ Equity

Inventory transfers to non-controlling interest | - |  | - |  |  |  |  | - |  |  | - |  |  | - |  |  | - |  |  | (6,829) |  |  | (6,829) |
Shares issued for exercise of warrants | 190,000 |  | 654 |  |  |  |  | - |  |  | (144) |  |  | - |  |  | - |  |  | - |  |  | 510 |
Shares issued for exercise of stock options | 1,049,476 |  | 1,863 |  |  |  |  | - |  |  | (801) |  |  | - |  |  | - |  |  | - |  |  | 1,062 |
Share-based compensation | - |  | - |  |  |  |  | - |  |  | 4,203 |  |  | - |  |  | - |  |  | - |  |  | 4,203 |
Capped calls | - |  | - |  |  |  |  | - |  |  | (12,006) |  |  | - |  |  | - |  |  | - |  |  | (12,006) |
Cumulative translation adjustment | - |  | - |  |  |  |  | - |  |  | - |  |  | - |  |  | 971 |  |  | - |  |  | 971 |
Balance at December 31, 2025 | 187,354,424 |  | $ | 382,842 |  |  |  |  | $ | - |  |  | $ | 56,733 |  |  | $ | (207,704) |  |  | $ | (2,626) |  |  | $ | 29,135 |  |  | $ | 258,380 |

See accompanying notes to the consolidated financial statements.
F-11

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
1.Nature of Operations
enCore Energy Corp. was incorporated on October 30, 2009, under the laws of British Columbia, Canada. enCore Energy Corp., together with its subsidiaries (collectively referred to as the “Company” or “enCore”), is principally engaged in the acquisition, exploration, development and extraction of uranium resource properties in the United States. The Company’s corporate headquarters is located at 13355 Noel Rd, Suite 1700, Dallas, Texas 75240.
The Company is focused on the extraction of domestic uranium in the United States. The Company utilizes the proven In-Situ Recovery technology (“ISR”) to provide necessary fuel for the generation of clean, reliable, and carbon-free nuclear energy.
The Company is an “Exploration Stage Issuer” as defined by Regulation S-K subpart 1300 (“S-K 1300”) of the Securities Act of 1933, as amended (the “Securities Act”) as it has not established proven or probable mineral reserves, as required by the Securities and Exchange Commission (“SEC”) to be defined as a Development Stage Issuer.
2.Summary of Significant Accounting Policies
Basis of Presentation
These consolidated financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC applicable to year end financial information. As of January 1, 2025, the Company became a U.S. Domestic Issuer, as defined by the SEC. Upon becoming a U.S. Domestic Issuer, and including the report herein, the Company has prepared its consolidated financial statements in accordance with United States Generally Accepted Accounting Principles (“U.S. GAAP”) for all periods presented.
These financial statements are presented in thousands of United States Dollars unless otherwise noted. There are certain disclosures where the Company discloses the amount in Canadian Dollars (“CAD,”) as this is the currency in which the instrument is denominated.
Principles of Consolidation
These financial statements incorporate the financial statements of the Company and its controlled subsidiaries. The Company consolidates entities that it controls due to ownership of a majority voting interest and consolidates variable interest entities (“VIEs”) when it is the primary beneficiary. All intercompany transactions and balances have been eliminated.
The Company has a 70% interest in the Alta Mesa Central Processing Plant (“CPP”) and Wellfield project (“Alta Mesa” or the “Alta Mesa Project”) with Boss Energy Limited (“Boss” or “Boss Energy”) owning the remaining 30%. The Company retained control after Boss acquired its interest in February 2024. Alta Mesa is considered a VIE, with the Company being considered the primary beneficiary. As a result, the Company consolidates the operations of Alta Mesa with an offsetting non-controlling interest being recorded. Refer to Note 8 – Sale of Minority Interest in Alta Mesa for more information related to the Boss transaction.
Non-controlling interests represent the portion of their equity which is not attributable, directly or indirectly, to the Company. These amounts are required to be reported as equity instead of as a liability on the consolidated balance sheets. Financial Accounting Standards Board (the “FASB”) Accounting Standard Codification (“ASC”) Topic 810, Consolidatio n requires net income or loss from non-controlling interests to be shown separately on the consolidated statements of operations.
Segments
Operating segments are defined as components of an entity for which discrete financial information is available and is regularly reviewed by the Chief Operating Decision Maker (“CODM”) in making decisions regarding resource allocation and performance assessment. The Company’s CODM is the Chief Executive Officer. The Company has one operating segment and one reportable segment. This reportable segment relates to uranium extraction, recovery and sales of uranium from mineral properties along with the exploration, permitting and
F-12

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
evaluation of uranium properties in the United States. The CODM assesses financial performance and decides how to allocate resources based on performance of mineral properties and the sale of uranium.
Mineral Rights and Properties
We have established the existence of mineralized materials for certain uranium projects, including our Rosita Uranium Project (“Rosita” or “Rosita Project”) and Alta Mesa Project (collectively, the “ISR Projects”). We have not established proven or probable reserves, as defined by S-K 1300, through the completion of a “final” or “bankable” feasibility study for any of the uranium projects we operate, including our ISR Projects. As a result, and despite the fact that we commenced the extraction of mineralized materials at our ISR Projects, we remain an Exploration Stage Issuer, as defined by the SEC, and will continue to remain as an Exploration Stage Issuer until such time that proven or probable reserves have been established.
As an Exploration Stage Issuer, expenditures relating to the acquisition of mineral rights are initially capitalized as incurred while exploration and pre-extraction expenditures are expensed as incurred until such time as we exit the Exploration Stage by establishing proven or probable reserves. Expenditures relating to exploration activities, such as drill programs to establish mineralized materials, are expensed as incurred. Expenditures relating to pre-extraction activities, such as the construction of mine wellfields, ion exchange (“IX”) facilities and disposal wells, are expensed as incurred until such time that proven or probable reserves are established for that project, after which expenditures relating to mine development activities for that particular project are capitalized as incurred. The Company presents construction and drilling costs within the exploration costs related to mineral properties in the investing cash flows section of the consolidated statements of cash flows. The remaining costs (e.g. maintenance and lease fees) are included in the operating cash flows section of the consolidated statements of cash flows.
When the Company starts to extract mineralized materials at our ISR Projects, the capitalized costs are depleted over estimated mineral resources using the units-of-production method. Depletion costs are capitalized to inventory then included in cost of sales as the inventory is sold on the consolidated statements of operations.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments, estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported revenues and expenses during the reported periods. Areas requiring significant judgments, estimates, and assumptions include the valuation of acquired mineral rights and properties, equity-method accounted investments, existence of impairment indicators for the Company’s long-lived assets, valuation and measurement of impairment losses on mineral rights and properties, valuation of asset retirement obligations, and valuation of stock options, share purchase warrants and share-based compensation. Other areas requiring estimates include depletion and amortization of mineral rights and properties and depreciation of property, plant and equipment. Actual results could differ significantly from those estimates and assumptions.
Foreign Currency
These financial statements are presented in U.S. Dollars, unless otherwise specified. The functional currency of enCore Energy Corp. is the Canadian Dollar. The functional currency of the Company’s subsidiaries is the U.S. Dollar based on the currency of the primary economic environment in which these subsidiaries operate.
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the date of the transaction. Foreign currency monetary items are translated at the period-end exchange rate. Non-monetary items measured at historical cost continue to be carried at the exchange rate at the date of the transaction. Non-monetary items measured at fair value are reported at the exchange rate at the date when fair values were determined.
F-13

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
Exchange differences arising on the translation of monetary items or on settlement of monetary items are recognized in profit or loss in the period in which they arise. Exchange differences arising on the translation of non-monetary items are recognized in other comprehensive loss in the consolidated statements of comprehensive loss to the extent that gains and losses arising on those non-monetary items are also recognized in other comprehensive loss. When the non-monetary gain or loss is recognized in profit or loss, the exchange component is also recognized in profit or loss.
On consolidation, the Company’s financial statements are translated into the presentation currency, being the U.S. Dollar. Assets and liabilities are translated at the period-end exchange rate. Income and expenses are translated at the average exchange rate for the period in which they arise. Exchange differences are recognized in accumulated comprehensive loss as a separate component within total stockholders’ equity, net of any related income tax effects, on the consolidated balance sheets.
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents consist of bank deposits and term deposits with an original maturity of three months or less. Restricted cash is excluded from cash and cash equivalents and is included in long-term assets. Restricted cash relates to collateralization of the Company’s performance obligations with an unrelated third party, also known as performance bonds. These funds are not available for the payment of general corporate obligations. The performance bonds are required for future restoration and reclamation obligations related to the Company’s operations. Refer to Note 9 – Asset Retirement Obligations and Restricted Cash.
Inventory, net
Inventory, net includes uranium concentrates and converted products including chemicals and are measured at the lower of cost and net realizable value. The cost of converted products and uranium concentrates is based on the first in first out method. Cost includes direct materials, direct labor and operational overhead expenses. Net realizable value is the estimated selling price in the ordinary course of business, less the estimated costs of completion and selling expenses. Consumable supplies and spares are valued at the lower of cost or replacement value.
Marketable Securities
Marketable equity securities consist of investments in publicly traded equity securities. The Company classifies and accounts for its marketable equity securities as available-for-sale. Subsequent to initial recognition, marketable equity securities are measured at fair value and changes therein are recognized as a component of loss on marketable securities, unrealized, in the consolidated statements of operations.
Equity Method Investments
Investments in an entity in which our ownership is greater than 20% but less than 50%, a 50/50 joint venture which the Company does not control, or an entity where other facts and circumstances indicate that we have the ability to exercise significant influence over its operating and financing policies, are accounted for using the equity method in accordance with FASB ASC Topic 323, Investments – Equity Method and Joint Ventures.
F-14

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
The Company accounts for equity method investments over which the Company exerts significant influence, but not control, over the financial and operating policies through the fair value option of FASB ASC Topic 825, Financial Instruments. The fair value of the investee’s common shares is measured based on its closing market price. Subsequent to initial recognition, equity method investments are measured at fair value and changes therein are recognized as a component of loss on marketable securities, unrealized in the consolidated statements of operations.
Property, Plant and Equipment
Property, plant and equipment is measured at cost less accumulated depreciation. Useful lives are based on the Company’s estimate at the date of acquisition and are depreciated straight-line as follows for each class of assets:

Category | Range
Uranium Plant | 15-25 years
Other Property Plant and Equipment | 3-5 years
Software | 2-3 years
Furniture | 3-5 years
Buildings | 10-40 years

Intangible Assets
Intangible assets consist of a data access agreement and data purchases, which are definite- and indefinite-lived assets, respectively. Definite-lived intangible assets are amortized over 14 years on a straight-line basis.
The Company reviews its definite-lived intangible assets for impairment when impairment indicators exist. When impairment indicators exist, the Company determines if the carrying value of its definite-lived intangible assets or asset groups exceeds the related undiscounted future cash flows. In cases where the carrying value exceeds the undiscounted future cash flows, the carrying value is written down to fair value. Fair value is determined using a discounted cash flow analysis.
The Company assesses its indefinite-lived intangible assets for impairment periodically to determine if any adverse conditions exist that would indicate impairment or when impairment indicators exist. The Company assesses its indefinite-lived intangible assets for impairment at least annually by comparing the fair value of the indefinite-lived intangible assets to their carrying value.
There were no indicators of impairment as of December 31, 2025 and 2024.
Impairment of Long-lived Assets
The Company reviews and evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Mineral rights and properties are monitored for impairment based on factors such as uranium prices, government regulations, our continued right to explore the area, exploration reports, assays, technical reports, drill results and continued plans to fund exploration and development programs on the property.
On each reporting date, the Company conducts a review of potential triggering events for all its mineral rights and properties. When events or changes in circumstances indicate that the related carrying amounts may not be recoverable, the Company carries out a review and evaluation of its long-lived assets in accordance with its accounting policy. Impairment losses are recognized as part of operating losses in the consolidated statements of operations.
F-15

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
Recoverability is measured by comparing the undiscounted future net cash flows to the net book value. When the net book value exceeds future net undiscounted cash flows, the fair value is compared to the net book value and an impairment loss may be measured and recorded based on the excess of the net book value over fair value. Fair value for mineral rights and properties prior to extraction is based on a combined approach of a discounted cash flow analysis and a market approach.
Future cash flows are estimated based on quantities of recoverable mineralized material, expected uranium prices (considering current and historical prices, trends and estimates), production levels, operating costs, capital requirements and reclamation costs, all based on the life-of-mine project plans. In estimating future cash flows, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of future cash flows from other asset groups. The Company's estimates of future cash flows are based on numerous assumptions, and it is possible that actual future cash flows will be significantly different than the estimates, as actual future quantities of recoverable minerals, uranium prices, production levels, costs and capital are each subject to significant risks and uncertainties.
There were no impairments for long-lived assets as of December 31, 2025 or 2024.
Operating Leases
The Company accounts for office leases under FASB ASC Topic 842, Leases, which requires leases to be recognized as assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The Company recognizes in the balance sheet a liability to make lease payments (the lease liability) and the right-of-use asset representing the right to the underlying asset for the lease term. For leases with a term of twelve months or less, the Company has made an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. The office leases all meet the definition of an operating lease.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recorded based on differences between the financial statement carrying values of existing assets and liabilities and their respective income tax bases (temporary differences), and losses carried forward. Deferred income tax assets and liabilities are measured using the enacted tax rates which will be in effect when the temporary differences are likely to reverse. The effect on deferred income tax assets and liabilities of a change in tax rates is included in operations in the period in which the change is enacted.
The Company records a valuation allowance to reduce deferred income tax assets to the amount that is believed more likely than not to be realized. When the Company concludes that all or part of the deferred income tax assets are not realizable in the future, the Company makes an adjustment to the valuation allowance that is charged to income tax benefit in the period such determination is made.
Asset Retirement Obligations
Various federal and state laws and regulations require our Company to reclaim the surface areas and restore groundwater quality to regulatory standards after the completion of extraction. We recognize the present value of the future restoration and remediation costs as an asset retirement obligation in the period in which we incur an obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets.
Asset retirement obligations (“ARO”) consist of estimated final well closure, plant and equipment decommissioning and removal and environmental remediation costs to be incurred by our Company in the future. The asset retirement obligation is estimated based on the current costs escalated at an inflation rate and discounted at a credit adjusted risk-free rate at inception. The asset retirement obligations are capitalized as part of the costs of the underlying assets and amortized over their remaining useful life. The asset retirement obligations are
F-16

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
accreted to an undiscounted value until they are settled. The accretion expenses are charged to depreciation, amortization, and accretion on the consolidated statement of operations and the actual retirement costs are recorded against the asset retirement obligations when incurred.
Convertible Senior Notes
The Company accounts for its convertible senior notes in accordance with ASC 470, Debt. The convertible senior notes are accounted for as a single liability measured at amortized cost, as no features does not require bifurcation. Debt issuance costs are recorded as a direct deduction from the carrying amount of the notes and amortized to interest expense over the contractual term using the effective interest method. Interest expense includes both the contractual coupon and the amortization of debt issuance costs. The convertible senior notes are classified as long-term debt in the consolidated balance sheets unless amounts become due within twelve months.
In connection with the issuance of the convertible senior notes, the Company entered into capped call transactions, which are accounted for separately as equity instruments in the consolidated balance sheets.
Share-based Compensation
We measure share-based awards, typically options and restricted stock units, at fair value on the date of the grant and expense the awards over the requisite service period of employees, brokers or consultants. The fair value of these stock options is measured at the grant date using the Black-Scholes option pricing model. The fair value of restricted stock units is measured at the fair value of our common shares based on the market price at the date of the grant. The share-based awards are equity-classified.
Share-based compensation expense related to awards with only service conditions having a graded vesting schedule is recorded on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in substance, multiple awards, while expense for all other awards are recognized on a straight-line basis.
The Company’s estimates may be impacted by certain variables including, but not limited to, stock price volatility, employee stock option exercise behaviors, additional stock option grants, the Company’s performance and related tax impacts.
Warrants
Warrants that are issued with shares issued have the proceeds allocated between the shares and the warrants based on their relative fair value. The fair value of the warrants is measured at the grant date using the Black-Scholes option pricing model. The fair value of the shares granted is based on the respective share’s publicly-traded market price.
Warrants issued to brokers are measured at their fair value on the vesting date. The fair value of stock options and warrants issued to brokers are estimated using the Black-Scholes option pricing model.
Financial Instruments
Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are recognized when the rights to receive or obligation to pay cash flows from the assets or liabilities have expired or been settled or have been transferred and the Company has transferred substantially all risks and rewards of ownership.
The Company classifies its financial instruments in the following categories: at fair value through profit and loss (“FVTPL”), at fair value through other comprehensive loss (“FVTOCI”), or at amortized cost. The Company determines the classification of financial assets at initial recognition. The classification of debt instruments is driven by the Company’s business model for managing the financial assets and their contractual cash flow characteristics. Equity instruments that are held for trading are classified as FVTPL. For other equity instruments, on the day of acquisition the Company can make an irrevocable election (on an instrument-by instrument basis) to
F-17

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
designate them at FVTOCI. Financial liabilities are measured at amortized cost, unless they are required to be measured at FVTPL (such as debt) or the Company has opted to measure them at FVTPL. Financial assets and liabilities carried at FVTPL are initially recorded at fair value and transaction costs are expensed in profit or loss. Realized and unrealized gains and losses arising from changes in the fair value of the financial assets and liabilities held at FVTPL are included in the consolidated statements of operations in the period in which they arise.
Revenue Recognition and Accounts Receivables
Our revenues are primarily derived from the sale of uranium concentrates under contracts with major U.S. utilities. Revenue is recognized when delivery is evidenced by book transfer at the applicable uranium storage facility. The sales contracts specify the quantity to be delivered, the price, payment terms and the year of the delivery. Under these contracts, each product delivered to the customer represents a separate performance obligation. The Company's contracts with its customers include minimum quantities to be delivered over terms greater than one year and may include fixed prices, market-based prices, and other variable pricing. In many contracts the variable consideration is allocated entirely to a wholly unsatisfied performance obligation, having met the criteria to do so. Other contracts may require certain variable consideration to be estimated and constrained as part of the transaction price.
Under the Company’s uranium contracts, it invoices customers after the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s uranium contracts generally do not give rise to contract assets or liabilities.
The Company applies the optional exemption not to disclose the remaining transaction price that is variable and allocated to wholly unsatisfied future quantities. The Company expects to recognize revenue related to fixed and unconstrained variable consideration of $117,895 through December 31, 2028, and $205,620 thereafter under the non-cancelable portion of these contracts.
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company evaluates its estimate of expected credit losses based on historical experience and current and forecasted future economic conditions for each portfolio of customers. As of December 31, 2025 and December 31, 2024, the Company did not have an allowance for expected credit losses for trade accounts receivable. As of December 31, 2025 the company had $4,944 of receivables from contracts with customers. The Company did not have receivables from contracts with customers as of December 31, 2024.
Concentrations of Credit Risk and Major Customers
The Company’s revenues are concentrated among a limited number of customers. For the year ended December 31, 2025, three customers accounted for approximately 63%, 25%, and 11% of total revenues. No other customer exceeded more than 10% of total revenues. For the year ended December 31, 2024, one customer accounted for approximately 77% of total revenues, and another customer accounted for approximately 23% of total revenues. No other customer exceeded more than 10% of the Company’s total revenue during the years ended December 31, 2025 and 2024.
As of December 31, 2025, one customer represented 100% of total trade accounts receivable. As of December 31, 2024, the Company did not have trade accounts receivable outstanding. The Company does not generally require collateral from its customers.
Geographic Concentrations
Substantially all of the Company’s revenues for the years ended December 31, 2025 and 2024 were derived from customers in the United States. As of December 31, 2025, substantially all trade accounts receivable were due from customers in the United States. The Company did not have significant revenues or receivables from customers outside the United States during the years ended December 31, 2025 and 2024
F-18

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
Loss per Share
Basic earnings or loss per share includes no potential dilution and is computed by dividing the earnings or loss attributable to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted earnings or loss per share reflects the potential dilution of securities that could share in the earnings or loss of our Company. Securities are excluded from the calculation of our diluted weighted average common shares outstanding if their effect would be anti-dilutive based on the treasury stock method or due to a net loss from continuing operations. Potential dilutive securities include stock options, restricted stock units, warrants and the Convertible Senior Notes (as defined below), which are excluded from the calculation of our diluted weighted average common shares outstanding as their effect would be anti-dilutive due to a net loss from continuing operations for the years ended December 31, 2025 and 2024. The Capped Calls Transactions (as defined below) are excluded from the loss per share diluted calculation because under U.S. GAAP purchased puts and calls are ignored in both basic and diluted loss per share.
Non-controlling Interests
Non-controlling interests are measured at their proportionate share of the acquiree’s identifiable net assets at the acquisition date and are adjusted at each reporting date for the net income (loss) attributable to that non-controlling interest during that period. The difference between the cash received and the proportionate share of the acquiree’s identifiable net assets is attributed to additional paid-in-capital.
Recently Adopted and Issued Accounting Standards
Recently Adopted Accounting Standards
In March 2024, the FASB issued ASU 2023-09, Income Taxes (Topic 740)-Improvements to Income Tax Disclosures. The ASU requires additional quantitative and qualitative income tax disclosures to allow readers of the consolidated financial statements to assess how the Company’s operations, related tax risks and tax planning affect its tax rate and prospects for future cash flows. For public business entities, the ASU was effective for annual periods beginning after December 15, 2024. The Company adopted this effective January 1, 2025. Adoption impacted disclosures but were not material to the Company's consolidated financial statements.
Recently Issued Accounting Standards
In November 2024, the FASB issued ASU 2024‑03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220‑40): Disaggregation of Income Statement Expenses. This ASU requires public business entities to disclose, in the notes to the financial statements, disaggregated information about certain expense categories included within income statement captions, without changing the presentation of the income statement. The guidance is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of adopting this ASU on its consolidated financial statements and related disclosures.
In July 2025, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2025‑05, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets. This ASU provides a practical expedient that permits entities to assume that current conditions as of the balance sheet date will remain unchanged for the remaining life of current accounts receivable and current contract assets arising from transactions accounted for under Topic 606. The guidance is effective for annual reporting periods beginning after December 15, 2025, including interim reporting periods within those annual periods. The Company did not elect to use the practical expedient as of December 31, 2025.
F-19

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
3.Inventory, Net
Costs of inventory consisted of the following:

| December 31, 2025 |  | December 31, 2024
Purchased uranium inventories | $ | - |  |  | $ | 16,614 |
Raw uranium | 3,558 |  |  | 1,564 |
Uranium concentrates from extraction | 1,647 |  |  | 2,718 |
Materials and supplies | 112 |  |  | 71 |
Total | $ | 5,317 |  |  | $ | 20,967 |

In order to measure inventory at the lower of cost and net realizable value for the years ended December 31, 2025 and 2024, the Company recognized impairment losses related to purchased uranium in the amount of $155 and $6,054, respectively. These losses are recorded in cost of goods sold in the Company’s consolidated statements of operations.
The Company recognized depletion in cost of sales of $4,891 and $1,334 for the years ended December 31, 2025 and 2024, respectively. Depletion relates to capitalized costs for mineral properties that were depleted to inventory using the units-of-production method and subsequently recognized in cost of sales upon the sale of related inventory.
4.Investments in Equity and Marketable Securities
The Company records both marketable securities and equity method investments at fair value. The Company has classified these investments on the Company’s consolidated balance sheets as marketable securities.
The following table summarizes the changes in fair value of the Company’s investment in equity securities as of December 31, 2025 and December 31, 2024:

| December 31, 2025 |  | December 31, 2024
Balance, beginning of year | $ | 24,883 |  |  | $ | 19,933 |
Investment in publicly traded companies | 34,396 |  |  | 9,798 |
Divestment of publicly traded companies | (11,151) |  |  | (548) |
Fair value loss on marketable securities | (5,681) |  |  | (2,711) |
Foreign exchange gain (loss) translation | 1,144 |  |  | (1,589) |
Balance, end of year | 43,591 |  |  | 24,883 |
Noncurrent marketable securities | - |  |  | (837) |
Current marketable securities | $ | 43,591 |  |  | $ | 24,046 |

During the year ended December 31, 2025, the company purchased an additional 32,863,144 shares and 1,214,853 warrants to purchase common stock of an investment and disposed of 6,969,770 shares and 3,681,372 warrants related to investments held as of December 31, 2024. As of December 31, 2025, the remaining shares and warrants are carried at a fair value of $43,591. These companies are publicly traded.
During the year ended December 31, 2024, the company purchased an additional 15,158,426 shares and 3,681,372 warrants to purchase common stock of an investment and disposed of 11,508,250 shares related to investments held as of December 31, 2023. As of December 31, 2024, the remaining shares and warrants are carried at a fair value of $24,046. These companies are publicly traded.
The realized gains on marketable securities sold during the years ended December 31, 2025 and 2024 was $9,613 and $248, respectively. The unrealized loss on marketable securities for the years ended December 31, 2025 and 2024 was $5,681 and $2,711, respectively.
F-20

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
5.Intangible Assets, Net
Intangible assets consist of the following as of December 31, 2025 and December 31, 2024:

| Gross Carrying Amount |  | Accumulated Amortization |  | Net Carrying Amount
December 31, 2025 |  |  |  |  |
Definite-lived: Data access agreement | $ | 263 |  |  | $ | 132 |  |  | $ | 131 |
Indefinite-lived: Data purchases | 1,334 |  |  | - |  |  | 1,334 |
| $ | 1,597 |  |  | $ | 132 |  |  | $ | 1,465 |
December 31, 2024 |  |  |  |  |
Definite-lived: Data access agreement | $ | 250 |  |  | $ | 107 |  |  | $ | 143 |
Indefinite-lived: Data purchases | 328 |  |  | - |  |  | 328 |
| $ | 578 |  |  | $ | 107 |  |  | $ | 471 |

Aggregate intangible asset amortization expense was $18 and $19 for the years ended December 31, 2025 and 2024, respectively, and was recorded in depreciation, amortization and accretion expense in the consolidated statements of operations.
Estimated future intangible asset amortization expense based upon the carrying value as of December 31, 2025 is as follows:

|  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | Thereafter |  | Total
Amortization expense |  | $ | 18 |  |  | $ | 18 |  |  | $ | 18 |  |  | $ | 18 |  |  | $ | 18 |  |  | $ | 41 |  |  | $ | 131 |

6.Property, Plant & Equipment, Net
Property, plant and equipment, net consists of the following:

| December 31, 2025 |  | December 31, 2024
Uranium plants | $ | 12,196 |  |  | $ | 8,292 |
Other property and equipment | 23,420 |  |  | 9,966 |
Construction in progress | 13,356 |  |  | 10,039 |
Total property, plant and equipment | 48,972 |  |  | 28,297 |
Less: Accumulated depreciation | (7,812) |  |  | (4,280) |
Total property, plant and equipment, net | $ | 41,160 |  |  | $ | 24,017 |

Aggregate depreciation expense was $3,532 and $2,113 for the years ended December 31, 2025 and 2024, respectively. These amounts are included in depreciation, amortization and accretion in the consolidated statements of operations.
F-21

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
7.Mineral Rights and Properties
As of December 31, 2025, we had mineral rights in the U.S. states of Texas, Wyoming, South Dakota, Colorado, Arizona and New Mexico. These mineral rights were acquired through asset acquisitions, lease or option agreements. As of December 31, 2025, annual maintenance payments of approximately $2,263 are required to maintain these mineral rights.
As of December 31, 2025 the activity of these mineral rights and properties was as follows:

| Amount
Balance, December 31, 2023 | $ | 274,490 |
Depletion capitalized into inventory | (2,568)
Balance, December 31, 2024 | $ | 271,922 |
Additions | 1,244 |
Depletion capitalized into inventory | (7,332) |
Balance, December 31, 2025 | $ | 265,834 |

The Company recorded additions to mineral rights and properties totaling $1,244 and $0 for the years ended December 31, 2025 and 2024, respectively. The additions in 2025 are related to the new asset retirement obligation for Upper Spring Creek. The Company recognized depletion of $7,332 and $2,568 that was capitalized to inventory during the years ended December 31, 2025 and 2024, respectively, utilizing the units-of-production method. Of this amount $2,221 and $482 was included in distributions to non-controlling interest and $1,490 and $1,234 was capitalized into ending inventory as of December 31, 2025 and 2024, respectively.
Texas
Alta Mesa Project
The Alta Mesa Project is located in Brooks County, Texas.
In February 2024, the Company completed several transactions under a master transaction agreement (the “MT Agreement”) with Boss Energy. The completion of these transactions resulted in the Company holding a 70% interest in the project while also remaining as the project manager. Boss Energy holds a 30% interest in the project. Refer to Note 8 – Sale of Minority Interest in Alta Mesa for further details. As of December 31, 2025 and 2024, $108,632 and $118,438 was capitalized as Mineral rights and property on the Company’s consolidated balance sheets.
Wyoming
Gas Hills
The Company owns a 100% interest in the Gas Hills Exploration Project located in the historic Gas Hills Uranium District 45 miles east of Riverton, Wyoming. The Gas Hills Project consists of approximately 1,280 surface acres and 12,960 net mineral acres of unpatented lode claims, a State of Wyoming mineral lease, and private mineral leases, within a brownfield site which has experienced extensive development including extraction and mill site production. For a more detailed discussion of the Gas Hills Project see the section titled “Material Properties,” below for this project..
Juniper Ridge
The Juniper Ridge Project is an Exploration Stage Property located in Wyoming. The Company owns a 100% interest in the Juniper Ridge Exploration Project located in Carbon Count and consists of approximately 640 surface acres and 3,240 net mineral acres of unpatented lode mining claims and a State of Wyoming mineral lease and is located within a brownfield site which has experienced extensive exploration, development, and mine production.
F-22

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
South Dakota
Dewey-Burdock
The Dewey-Burdock Project is an ISR uranium project located near Edgemont, South Dakota.
Notably, the advanced stage Dewey-Burdock Uranium Project (“Dewey-Burdock” or “Dewey-Burdock Project”) in South Dakota has demonstrated ISR resources, including a 2019 Preliminary Economic Assessment (“PEA”) citing robust economics. The Dewey-Burdock Project has its source material license from the U.S. Nuclear Regulatory Commission (“NRC”) and its underground injection permits and aquifer exemption from the US Environmental Protection Agency (“EPA”).
On September 2, 2025, the Company announced that the Dewey-Burdock Project had been approved for inclusion in the FAST-41 Program by the U.S. Federal Permitting Improvement Steering Council (“Permitting Council”). This is a component of the implementation of President Trump’s Executive Order on Immediate Measures to Increase American Mineral Production. The Dewey-Burdock Project received its Source and Byproduct Materials License in 2014, from the NRC, now under timely renewal, and will work with the NRC as the lead agency for federal permitting. The Company’s objective is to advance the Dewey-Burdock Project into development and operation utilizing the ISR uranium extraction process. Under the Executive Order, the Permitting Council identifies priority infrastructure and critical mineral projects to receive accelerated permitting review. The addition of the first South Dakota ISR project supports the domestic uranium production focus of the United States. This focus enables the development of essential clean energy, extracted through environmentally responsible ISR technology, to provide affordable, reliable domestic energy.
On September 16, 2025, the Company announced that the EPA Environmental Appeals Board (“EAB”) has denied in full a petition for review filed by the Oglala Sioux Tribe, Black Hills Clean Water Alliance, and NDN Collective against the EPA’s issuance of Class III and Class V Underground Injection Control (“UIC”) permits for the Company’s 100%-owned Dewey Burdock Project in South Dakota. The decision allows the Dewey-Burdock Project to advance through federal permitting with the intent to commence state permitting activities in 2025, accelerating the Project towards development ahead of schedule.
New Mexico
McKinley, Crownpoint and Hosta Butte
In April 2025, the Company executed a definitive sale and purchase agreement to sell certain mineral rights and properties that were classified as held for sale and owned by NM Energy Holding Canada Corp. (“NM Energy Canada,”) an enCore subsidiary (the “Verdera Transaction”) that holds the Crownpoint and Hosta Butte projects located in McKinley County, New Mexico to Verdera Energy Corp. (“Verdera”) pursuant to a share purchase agreement, dated March 17, 2025 (the “Share Purchase Agreement”). As a result of the Verdera Transaction, the Company contingently received 50,000,000 Preferred Shares of Verdera. The Preferred Shares provide voting rights related to approval of a “Going Public Transaction”, which is defined as a transaction that results in the common shares of Verdera being listed on a Canadian stock exchange and concurrent registration under the Exchange Act, which the Company has agreed to vote in favor of so long as the Going Public Transaction results in aggregate gross proceeds to Verdera of at least CAD $20 million. In the event that Verdera did not execute the Going Public Transaction by February 23, 2026, the Company would have the right to reacquire NM Energy Canada from Verdera in exchange for transferring all of the contingently received 50,000,000 Preferred Shares of Verdera back. As such, the recognition of the fair value related to the Preferred Shares had no impact to the financial statements as of December 31, 2025 and 2024 as the “Going Public Transaction” related contingencies were not resolved as of such dates. Subsequent to December 31, 2025, Verdera completed its listing on TSX-V and 15,000,000 Preferred Shares were converted into common shares of Verdera, See Note 19 - Subsequent Events for further details
F-23

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
8.Sale of Minority Interest in Alta Mesa
On February 26, 2024, pursuant to the terms of the MT Agreement, Boss Energy acquired a 30% equity interest in a new limited liability company (the “JV Alta Mesa”) that was formed to hold the Alta Mesa Project, in exchange for a payment of $60,000. The Company holds 70% equity in the JV Alta Mesa. Upon the closing of the transaction, the parties entered into an agreement which governs the JV Alta Mesa. Pursuant to the agreement, the Company acts as manager of the JV Alta Mesa and is entitled to a management fee.
Boss also acquired 2,564,102 common shares of the Company for total proceeds to the Company of $10,000. Finally, the parties also entered into a strategic collaboration agreement for the collaboration and research to develop the Company’s prompt fission neutron technology, to be financed equally by each party. The terms of the agreement and the disposal of a 30% interest in the JV Alta Mesa support that control was retained both before and after Boss acquired their interest, and that joint control is not present. As such, the Company will continue to consolidate the operations of the JV Alta Mesa with the non-controlling interest being recorded.
The table below is a summary of the accounting for recognition of the initial non-controlling interest on Boss acquiring 30% interest in the JV Alta Mesa. The difference between the percentage of the net assets attributable to Boss and the consideration received is included as part of additional paid-in capital.

| Amount
Boss Initial Non-Controlling Interest |
Cash received | $ | 60,000 |
Additional paid-in capital | (20,447) |
Non-controlling interest | $ | 39,553 |

The Company, upon initial recognition and formation of the joint venture and the sale of minority interest to Boss, recognized a decrease in additional paid-in capital and an increase in income tax benefit of $4,989 due to there being a difference between the selling price of the minority interest and the book basis of the non-controlling interest as of the formation date.
The table below is a summary of the accounting for the Non-Controlling Interest as of December 31, 2025 and 2024..

| Amount
Initial non-controlling interest | $ | 39,553 |
Net loss for the period attributable to non-controlling interest | (6,601) |
Inventory transfers to non-controlling interest | (1,905) |
Contributions from non-controlling interest | 1,759 |
Balance at December 31, 2024 | $ | 32,806 |
Balance at January 1, 2025 | $ | 32,806 |
Net loss for the period attributable to non-controlling interest | (6,167) |
Inventory transfers to non-controlling interest | (6,829) |
Contributions from non-controlling interest | 9,325 |
Balance at December 31, 2025 | $ | 29,135 |

F-24

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
9.Asset Retirement Obligations and Restricted Cash
The asset retirement obligations continuity summary is as follows:

| Amount
Balance, December 31, 2023 | $ | 10,828 |
Accretion | 1,065 |
Settlement | (399) |
Change in estimates | 5,424 |
Balance, December 31, 2024 | $ | 16,918 |
Additions | 1,243 |
Accretion | 1,831 |
Settlement | (131) |
Change in estimates | (946) |
Balance, December 31, 2025 | $ | 18,915 |

The asset retirement obligation represents the Company’s estimate of the present value of future reclamation costs, discounted using a credit‑adjusted risk‑free interest rate of 11.0% and an inflation rate of 2.5% for each of the years ended December 31, 2025 and 2024. The Company expensed the change in estimate for the years ended December 31, 2025 and 2024 as a result of these being adjustments to the estimate for asset retirement obligations that were acquired as part of asset acquisitions.
As of December 31, 2025 and 2024, the undiscounted cash flows related to asset retirement obligations totaled $26,443 and $23,529, respectively.
As of December 31, 2025 and 2024, the Company deposited $8,388 and $7,751, respectively, for collateralization of its performance obligations with an unrelated third party also known as performance bonds. These funds are not available for the payment of general corporate obligations. The performance bonds are required for future restoration and reclamation obligations related to the Company’s operations. These funds are categorized as restricted cash on the Company’s consolidated balance sheets.
10.Commitments and Contingencies
General Legal Matters
On March 14, 2025, a purported shareholder of the Company filed a putative federal securities class action, in the United States District Court for the Southern District of Texas against the Company and certain of its current and former officers and directors (the “Litigation”).
The complaint asserts claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) and SEC Rule 10b-5 and principally alleges that the defendants failed to disclose that: (1) enCore lacked effective internal controls over financial reporting; (2) enCore could not capitalize certain exploratory and development costs under U.S. GAAP; and (3) as a result, the Company’s net losses would materially increase. The foregoing omissions allegedly made defendants’ positive public statements about Company’s business, operations, and prospects materially false or misleading and artificially inflated the Company’s share price during the class period. The Litigation seeks damages and costs. Management believes that this litigation is preliminary in nature and the Company believes that an adverse outcome is not probable or estimable at this time.
On April 23, 2025, the Company’s former Chief Executive Officer filed a demand for arbitration with the Judicial Arbiter Group against the Company. The demand principally alleged that the Company breached the former Chief Executive Officer’s employment agreement by refusing to pay him the amount he claimed to be owed under the employment agreement had the Company terminated his employment without just cause. Therefore, the former Chief Executive Officer sought damages for the amounts allegedly owed under the employment agreement for
F-25

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
termination without just cause, including salary, a 2024 cash bonus, an annual targeted bonus and his COBRA coverage for 24 months. On October 10, 2025, the parties entered into a Confidential Settlement and General Release Agreement. As of December 31, 2025, the Company had satisfied its obligations under the agreements.
On June 2, 2025, the Company’s former Chief Operating Officer filed a demand for arbitration with the Judicial Arbiter Group against the Company. The demand principally alleges that the Company breached the former Chief Operating Officer’s employment agreement by refusing to pay him the amount he claimed to be owed under the employment agreement had the Company terminated his employment without just cause. Therefore, the former Chief Operating Officer seeks damages for the amounts allegedly owed under the employment agreement for termination without just cause, including salary and his COBRA coverage for 24 months. Management believes that this demand for arbitration is preliminary in nature and that a loss is not probable or estimable at this time.
The Company is subject to routine litigation incidental to our business. The Company is not currently a party to any material legal proceedings that Management believes would be likely to have a material adverse effect on our financial position, results of operations or cash flows.
Mineral Property Commitments
The Company enters into commitments with federal and state agencies and private individuals to lease mineral rights. These leases are renewable annually. As of December 31, 2025, annual maintenance payments of approximately $2,263 are required to maintain these mineral rights.
Sales Contracts
The Company’s sales commitments, for all sales contracts, are presented in pounds (in thousands) below.

Year |  | Volume (in pounds)
2026 |  | 900
2027 |  | 850
2028 |  | 1,000
2029 |  | 1,500
2030 |  | 1,200
Thereafter |  | 2,500
Total |  | 7,950

Reclamation Bonds
The Company has indemnified third-party companies to provide reclamation bonds as collateral for the Company’s ARO. The Company is obligated to replace this collateral in the event of a default and is obligated to repay any reclamation or closure costs due. As of December 31, 2025 and December 31, 2024, the Company had $8,388 and $7,751, respectively, posted as collateral against an undiscounted ARO of $26,443 and $23,529, respectively.
11.Leases
The Company leases office space in the United States and Canada under non‑cancelable operating lease agreements. The Company does not have any finance leases. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets, and lease expense related to these leases is recognized on a straight‑line basis over the lease term.
Operating lease right‑of‑use (“ROU”) assets and lease liabilities are recognized at lease commencement. Lease liabilities are measured based on the present value of future lease payments over the lease term. As the implicit
F-26

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
rate is not readily determinable, the Company uses its incremental borrowing rate at lease commencement. ROU assets are measured based on the related lease liabilities, adjusted for prepaid rent, accrued rent, and lease incentives.
The Company has elected the practical expedient to not separate lease and non‑lease components for all leases. Operating lease expense is recognized on a straight‑line basis over the lease term. Variable lease payments, which primarily relate to non‑fixed operating costs, are excluded from the measurement of ROU assets and lease liabilities and are expensed as incurred.
As of December 31, 2025, the Company did not have any material leases that had not yet commenced. Operating lease cost was $263 and $208 for the years ended December 31, 2025 and 2024, respectively, which was included in general and administrative expenses on the Company’s consolidated statements of operations.
The following table represents the weighted-average remaining lease term and discount rate:

| December 31,
| 2025 |  | 2024
Operating Leases: |  |  |
Weighted-average remaining lease term (in years) | 9.50 |  | 3.08
Weighted-average discount rate | 7.0% |  | 7.0%

As of December 31, 2025, future minimum lease payments for the Company’s operating lease liabilities are as follows:

Year Ending December 31, | Amount
2026 | $412
2027 | 559
2028 | 495
2029 | 385
2030 | 395
Thereafter | 2,300 |
Total future lease payments | $4,546
Less: imputed interest | (1,283) |
Present value of lease liabilities | $3,263

As of December 31, 2025 and 2024, the following balances related to the Company’s operating leases are recorded in the consolidated balance sheets:

| December 31,
| 2025 |  | 2024
Right of use asset | $3,083 |  | $310
Lease liability, current | $186 |  | $130
Lease liability, non-current | $3,077 |  | $202

Supplemental cash flow information related to leases was as follows:
F-27

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)

| Years Ended December 31,
| 2025 | 2024
Cash paid for operating leases | $203 | $201
Supplemental disclosure of noncash leasing activities: |  |
Right-of-use-assets obtained in exchange for new operating lease liabilities | $3,006 | $67

12.Fair Value
Fair value accounting establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The three levels of the fair value hierarchy are described below:
•Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities;
•Level 2 - Quoted prices in markets that are not active, quoted prices for similar assets or liabilities in active markets, quoted prices or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability, and model-based valuation techniques for which all significant inputs are observable in the market or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and
•Level 3 - Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).
The financial instruments, including cash and cash equivalents, accounts and other receivables, restricted cash, accounts payable and accrued liabilities, are carried at cost, which approximates their fair values due to the immediate or short-term maturity.
The Company’s investments in equity securities are publicly traded stocks measured at fair value and classified within Level 1 in the fair value hierarchy. Level 1 equity securities use quoted prices for identical assets in active markets.
The Company’s investments include certain investments accounted for at fair value consisting of warrants that are valued using the Black-Scholes option model based on observable inputs and as such are classified within Level 2 of the hierarchy. The warrant asset is included in marketable securities, long-term on the consolidated balance sheets.
The Company’s Convertible Senior Notes due 2030 (the “Convertible Senior Notes”) debt component was fair valued utilizing a 6.6% discount rate, which is the Company’s estimate of the market discount rate for this arrangement. This is classified within Level 2 of the hierarchy.

| Level 1 |  | Level 2 |  | Level 3 |  | Total
December 31, 2025 |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |
Marketable securities, current and non-current | $ | 43,460 |  |  | $ | - |  |  | $ | - |  |  | $ | 43,460 |
Warrant asset | - |  |  | 131 |  |  | - |  |  | 131 |
Total assets | $ | 43,460 |  |  | $ | 131 |  |  | $ | - |  |  | $ | 43,591 |
Liabilities: |  |  |  |  |  |  |
Convertible debt, non-current | - |  |  | 109,986 |  |  | - |  |  | 109,986 |
Total liabilities | $ | - |  |  | $ | 109,986 |  |  | $ | - |  |  | $ | 109,986 |

F-28

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)

| Level 1 |  | Level 2 |  | Level 3 |  | Total
December 31, 2024 |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |
Marketable securities, current and non-current | $ | 24,314 |  |  | $ | - |  |  | $ | - |  |  | $ | 24,314 |
Warrant asset | - |  |  | 569 |  |  | - |  |  | 569 |
Total assets | $ | 24,314 |  |  | $ | 569 |  |  | $ | - |  |  | $ | 24,883 |

13.Stockholders’ Equity
The authorized shares of the Company consist of an unlimited number of common and preferred shares, both without par value. All proceeds received for issuances of common shares are attributed to common shares on the Company’s consolidated balance sheets.
During the year ended December 31, 2025, the Company issued:
i)190,000 common shares on the exercise of warrants, for gross proceeds of $654. In connection with the warrants exercised, the Company reclassified $144 from additional paid-in capital to share capital.
ii)1,049,476 common shares on the exercise of stock options, for gross proceeds of $1,863. In connection with the stock options exercised, the Company reclassified $801 from additional paid-in capital to common shares.
iii)The Company entered into the capped call transactions (the “Capped Call Transactions” on August 20 and August 22, 2025. The Capped Calls Transaction are generally intended to reduce or offset the potential economic dilution to the common shares upon the conversion of the Company’s Convertible Senior Notes. As the Capped Calls Transactions are considered indexed to the Company’s own equity and are equity classified, they are recorded in shareholders’ equity and are not accounted for as a derivative. The costs of $12,006 incurred in connection with the Capped Calls Transactions were recorded as a reduction to additional paid-in capital. The Capped Calls Transactions are excluded from the calculation of diluted earnings per share, as they would be anti-dilutive under treasury stock method.
During the year ended December 31, 2024, the Company issued:
i)2,564,102 units to Boss in February of 2024, for a private placement at a price of $3.90 per unit for gross proceeds of $10,000.
ii)6,872,143 common shares to extinguish the convertible note with a carrying value of $23,117 in February 2024.
iii)8,781,985 common shares on the exercise of warrants, for gross proceeds of $25,471. In connection with the warrants exercised, the Company reclassified $7,902 from additional paid-in capital to share capital.
iv)2,267,155 common shares on the exercise of stock options, for gross proceeds of $1,760. In connection with the stock options exercised, the Company reclassified $1,919 from additional paid-in capital to common stock.
v)495,765 common shares sold in accordance with the Company’s ATM program for gross proceeds of $2,008.
Share Purchase Warrants
F-29

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
A summary of the status of the Company’s warrants as of December 31, 2025 and 2024, and changes during the years then ended is as follows:

| Number of Warrants |  | Weighted Average Exercise Price (CAD)
Outstanding, December 31, 2023 | 31,461,804 |  | C$4.04
Granted | 500 |  | 3.90 |
Exercised | (8,781,985) |  | 3.97 |
Expired | (2,746,235) |  | 5.95 |
Outstanding, December 31, 2024 | 19,934,084 |  | C$3.81
Exercised | (190,000) |  | 3.75 |
Expired | (2,444) |  | 3.27 |
Outstanding, December 31, 2025 | 19,741,640 |  | C$3.81

As of December 31, 2025, share purchase warrants outstanding were as follows:

|  |  |  | Warrants Outstanding December 31, 2025
Warrant Price Per Share (CAD) |  | Number of Warrants |  | Weighted Average Remaining Life (years) |  | Weighted Average Exercise Price (CAD)
C$4.05 |  | 3,835,440 |  | 0.02 |  | C$4.05
C$3.75 |  | 15,906,200 |  | 0.10 |  | C$3.75
Total |  | 19,741,640 |  | 0.12 |  | C$3.81

14.Share-Based Compensation
Options
During the years ended December 31, 2025 and 2024, the Company recognized stock option expense of $2,487 and $4,788, respectively, for the vested portion of the stock options.
The Company recognized share-based compensation in connection with two stockholders approved equity plans. The Stock Option Plan (the “Stock Option Plan”) which was adopted in 2015 and later amended in 2021, and the 2024 Long Term Incentive Plan (the “LTIP”) which was adopted in 2024 and replaced the Stock Option Plan. Both plans are detailed below.
Stock Option Plan
Under the Stock Option Plan the Company was authorized to grant options to officers, directors, employees and consultants, enabling them to acquire common shares of the Company upon exercise of the options. The number of shares reserved for issuance under the Stock Option Plan could not exceed 10% of the outstanding common shares at the time of the grant. The options could be granted for a maximum of five years and vested as determined by the Company’s Board of Directors (the “Board”). No further grants are authorized under Stock Option Plan as a result of the adoption of the LTIP. See further details on the LTIP below.
Activity of outstanding stock options under the Stock Option Plan for the years ended December 31, 2025 and 2024 are as follows:
F-30

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)

| Number of stock options |  | Weighted average exercise price (CAD)
Balance, December 31, 2023 | 8,412,882 |  |  | C$2.63
Exercisable, December 31, 2023 | 5,921,267 |  |  | C$2.39
Granted | 2,804,000 |  |  | 5.75
Exercised | (2,267,155) |  |  | 1.06
Forfeited/expired | (300,001) |  |  | 4.42
Balance, December 31, 2024 | 8,649,726 |  |  | C$3.99
Exercisable, December 31, 2024 | 6,169,340 |  |  | C$3.55
Exercised | (1,049,476) |  |  | 1.41
Forfeited/expired | (1,764,791) |  |  | 4.28
Balance, December 31, 2025 | 5,835,459 |  |  | C$4.37
Exercisable, December 31, 2025 | 5,359,459 |  |  | C$4.25

As of December 31, 2025, stock options under the Stock Option Plan outstanding and exercisable were as follows:

|  |  | Options Outstanding | Options Exercisable
|  |  | December 31, 2025 | December 31, 2025
Option price per share (CAD) | Options # |  | Weighted average remaining life (years) |  | Weighted average exercise price (CAD) | Options # | Weighted average exercise price (CAD)
C$2.40 - 3.79 | 1,866,541 |  |  | 0.69 |  | C$2.95 | 1,866,541 |  | C$2.95
C$4.20 - 5.76 | 3,968,918 |  |  | 1.42 |  | C$5.03 | 3,492,918 |  | C$4.94
| 5,835,459 |  |  | 2.11 |  | C$4.37 | 5,359,459 |  | C$4.25

As of December 31, 2025, the aggregate intrinsic value of all outstanding stock options granted and vested under the Stock Option Plan was estimated at $516. As of December 31, 2025, the unrecognized compensation cost related to unvested stock options under the Stock Option Plan was $265, which is expected to be recognized over a weighted average period of 0.4 years.
A summary of the Company’s unvested stock option activity under the Stock Option Plan is as follows:

| Number of Shares |  | Weighted Average Grant Date Fair Value (CAD)
Outstanding, December 31, 2023 | 2,491,616 |  | C$1.85
Granted | 2,804,000 |  | 2.78 |
Vested | (2,588,666) |  | 2.18 |
Forfeited | (226,564) |  | 2.28 |
Outstanding, December 31, 2024 | 2,480,386 |  | C$2.52
Vested | (1,415,386) |  | 2.45 |
Forfeited | (589,000) |  | 2.46 |
Outstanding, December 31, 2025 | 476,000 |  | C$2.79

There were no stock options granted under the Stock Option Plan during the year ended December 31, 2025.
F-31

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
The Company granted an aggregate of 2,804,000 stock options to directors, officers, employees, and an accounting advisory consultant of the Company under the Stock Option Plan during the year ended December 31, 2024. A fair value of $5,695 was calculated for these options as measured at the grant date using the Black-Scholes option pricing model during the year ended December 31, 2024.
The Company’s standard stock option vesting schedule calls for 25% every six months commencing six months after the grant date.
2024 Long Term Incentive Plan
In August 2024, the Company adopted the LTIP to replace the Stock Option Plan. Awards previously issued and outstanding pursuant to the Stock Option Plan will continue to be governed by the Stock Option Plan.
The number of common shares reserved for issuance pursuant to awards granted under the LTIP will not, in the aggregate, exceed 10% of the issued and outstanding common shares at the time of the grant. No award, other than an option, may vest before the date that is one year following the date on which the award is granted, except in the case of accelerated vesting as defined in the LTIP.
Activity of outstanding stock options under the LTIP for the years ended December 31, 2025, and 2024 is as follows:

| Number of stock options |  | Weighted average exercise price (USD)
Balance, December 31, 2023 | - |  |  | $ | - |
Granted | 225,000 |  |  | $ | 4.07 |
Balance, December 31, 2024 | 225,000 |  |  | $ | 4.07 |
Granted | 1,060,000 |  |  | 3.21 |
Forfeited/expired | (225,000) |  |  | 4.07 |
Balance, December 31, 2025 | 1,060,000 |  |  | $ | 3.21 |
Exercisable, December 31, 2025 | - |  |  | $ | - |

As of December 31, 2025, stock options outstanding and exercisable under the LTIP were as follows:

|  |  | Options Outstanding | Options Exercisable
|  |  | December 31, 2025 | December 31, 2025
Option price per share | Options # |  | Weighted average remaining life (years) |  | Weighted average exercise price (USD) | Options # | Weighted average exercise price (USD)
$ | 3.21 |  | 1,060,000 |  |  | 4.63 |  | $ | 3.21 |  | - |  | $ | - |
| 1,060,000 |  |  | 4.63 |  | $3.21 | - |  | $0.00

F-32

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
A summary of the Company’s unvested stock option activity under the LTIP is as follows:

| Number of Shares |  | Weighted Average Grant Date Fair Value (USD)
Outstanding, December 31, 2023 | - |  | $ | - |
Granted | 225,000 |  | 4.23 |
Outstanding, December 31, 2024 | 225,000 |  | $ | 4.23 |
Granted | 1,060,000 |  | 3.21 |
Forfeited | (225,000) |  | 4.23 |
Outstanding and unvested, December 31, 2025 | 1,060,000 |  | $ | 3.21 |

As of December 31, 2025, the aggregate intrinsic value of all outstanding stock options granted and vested under the LTIP was estimated at $11. As of December 31, 2025, the unrecognized compensation cost related to unvested stock options under the LTIP was $1,454, which is expected to be recognized over a weighted average period of 1.6 years.
A fair value of $3,403 was calculated for these options as measured at the grant date using the Black-Scholes option pricing model during year ended December 31, 2025. There were 1,060,000 stock options granted under the LTIP during the year ended December 31, 2025. The weighted average assumptions used in calculating the fair values as of December 31, 2025, are as follows:

|  | December 31, 2025
Exercise price |  | $3.21
Share price |  | $3.21
Risk-free rate |  | 3.62 | %
Expected life (in years) |  | 3.33
Expected volatility |  | 74.30 | %
Expected dividend yield |  | 0.00 | %
Weighted average fair value |  | $1.68

The Company has elected to utilize the simplified method for determining the expected life of the options. This is due to the stock options granted being considered “plain vanilla” in accordance with SAB Topic 14 in ASC 718. This simplified method allows for the average of the vesting period and contractual life.
Restricted Stock Units
Under the LTIP, restricted stock units (“RSUs”) may be granted to the participants and generally vest over multi-year service periods, typically two to five years for officers, employees and consultants and annually for directors.
During the year ended December 31, 2025, the Company granted 4,024,208 RSUs to officers and directors under its LTIP. The following table summarizes the Company’s RSU activity for the year ended December 31, 2025:
F-33

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)

| Number of RSUs |  | Weighted Average Remaining Vesting Term (years) |  | Weighted Average Grant Date Fair Value (USD)
Balance, December 31, 2024 | - |  | - |  | $ | - |
Granted | 4,024,208 |  |  | 2.65 |  | 3.36
Forfeited | (97,783) |  | - |  | 3.47
Balance, December 31, 2025 | 3,926,425 |  | 2.42 |  | $ | 3.36 |

No RSUs were vested as of December 31, 2025.
The Company recognized $1,716 of compensation expense related to RSUs during the year ended December 31, 2025. As of December 31, 2025, unrecognized compensation cost related to unvested RSUs was $11,428, which is expected to be recognized over a weighted average period of 2.42 years.
15.Debt
Convertible Senior Notes
On August 19, 2025, the Company issued $115,000 aggregate principal amount of Convertible Senior Notes. The Convertible Senior Notes bear interest at a rate of 5.5%, annually, payable semiannually in arrears, and matures on August 15, 2030.
The net proceeds from the offering of the Convertible Notes were approximately $109,657, after deducting the debt issuance costs. The Company used $11,549 of the net proceeds from the Convertible Senior Notes offering to pay the costs of entering into the Capped Call Transactions in connection with the Convertible Senior Notes and approximately $10,573 of the net proceeds from the Convertible Senior Notes offering to repay amounts outstanding under its Uranium Loan Agreement (as defined below). See Note Payable - Related Party below for additional information.
The Convertible Senior Notes were issued pursuant to, and are governed by, an indenture, dated August 22, 2025 (the “Indenture”), between the Company and U.S. Bank National Association, as trustee (the “Trustee”). The initial conversion rate for the Convertible Senior Notes is 303.9976 shares per $1,000 principal amount of the Convertible Senior Notes, which represents an initial conversion price of approximately $3.29 per common share, and is subject to adjustment upon the occurrence of certain specified events as set forth in the Indenture. Upon conversion, the Company will pay or deliver, as applicable, cash, common shares or a combination of cash and common shares.
Upon the occurrence of a “make-whole fundamental change” (as defined in the Indenture), the Company will in certain circumstances increase the conversion rate for a specified period of time. In addition, upon the occurrence of a “fundamental change” (as defined in the Indenture), holders of the Convertible Senior Notes may require the Company to repurchase their Convertible Senior Notes at a cash repurchase price equal to the principal amount of the Convertible Senior Notes to be repurchased, plus accrued and unpaid interest, if any.
The Convertible Senior Notes may be redeemed, in whole or in part, at the Company’s option at any time, and from time to time, on or after August 21, 2028 and on or before the 40th scheduled trading day immediately before the maturity date, at a cash redemption price equal to the principal amount of the Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, but only if the last reported sale price per common share exceeds 130% of the conversion price on (i) each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date the Company sends the related redemption notice, and (ii) the trading day immediately before the date the Company sends such notice. The indenture contains specified events of default and our failure to pay principal, interest or other amounts when due or within the relevant grace period on our Convertible Senior Notes would constitute an event of default under the Indenture, which could result in an acceleration of the maturity of the Convertible Senior Notes.
F-34

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
The Convertible Senior Notes are accounted for as a single liability measured at amortized cost, with debt issuance costs recorded as a direct deduction from the carrying amount of the Convertible Senior Notes and amortized over the contractual term using the effective interest method.

|  | December 31, 2025
Convertible Senior Notes due 2030 |  | $115,000
Less: Unamortized debt issuance costs |  | (5,014) |
Total debt |  | 109,985 |
Less: Current portion of debt |  | - |
Long-term debt |  | $109,985

The effective interest rate of the Convertible Senior Notes was 6.6%, which includes the amortization of debt issuance costs. For the year ended December 31, 2025, the Company recognized interest expense of $2,266 and amortization of debt issuance costs of $329 related to the Convertible Senior Notes.
Capped Call Transactions
In connection with the Convertible Senior Notes in August 2025, the Company entered into the Capped Call Transactions.
The Capped Calls are intended to reduce potential dilution to the Company’s common shares upon conversion of the Convertible Senior Notes and/or offset potential cash payments the Company may be required to make in excess of the principal amount of the Convertible Senior Notes, with such reduction or offset subject to a cap. The Capped Calls are subject to customary anti‑dilution adjustments substantially similar to those applicable to the Convertible Senior Notes and are separate transactions that do not form part of the terms of the Convertible Senior Notes.
The Capped Calls have an initial strike price of $3.29 per common share and an initial cap price of $4.52 per common share, each subject to customary anti‑dilution adjustments.
The Capped Calls are considered indexed to the Company’s own equity and are classified as equity. Accordingly, the Capped Calls are recorded in shareholders’ equity and are not accounted for as derivative instruments. The costs of $12,006 incurred in connection with the Capped Calls were recorded as a reduction to additional paid‑in capital. The Capped Calls are excluded from the calculation of diluted earnings per share, as they would be anti‑dilutive under the treasury stock method.
Note Payable - Related Party
On December 5, 2023, the Company, through a subsidiary, entered into a loan agreement (the “Uranium Loan”) with Boss to borrow up to 200,000 pounds of uranium from Boss. The Uranium Loan initially bore interest of 9% per annum and was repayable in 12 months in cash or uranium at the election of Boss. Boss is considered a related party given its minority ownership of the Alta Mesa JV. On February 21, 2025, the Company, through a subsidiary, amended the Uranium Loan effective February 26, 2025, to revise the schedule of repayment of the loaned uranium and to update the redelivery and repayment methods.
On June 27, 2025, the Company and Boss amended the Uranium Loan to extend the repayment date one week to July 3, 2025. On July 2, 2025, the Company and Boss, among other things, extended the loan repayment date of the Uranium Loan to December 27, 2025, increase the interest rate to 10% per annum and provide for a cash facility of $3,600.
On August 22, 2025, the Company repaid the Uranium Loan in full and terminated the Uranium Loan. The total payoff amount was $10,573, consisting of $10,054 in principal and $519 in accrued interest. As a result, there was no outstanding balance as of December 31, 2025.
F-35

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
During the years ended December 31, 2025, and 2024, the Company incurred interest expense of $797 and $1,531, respectively.
Convertible Promissory Note
On February 14, 2023, the Company issued a secured convertible promissory note (the “Convertible Promissory Note”) in connection with the Alta Mesa asset acquisition.
The principal value of the Convertible Promissory Note was $60,000, and the Convertible Promissory Note was secured by certain assets of the Company pursuant to the terms of a Pledge Agreement, a Security Agreement, and a Guaranty Agreement between the parties.
The principal portion of the Convertible Promissory Note was convertible at any time and at the option of the holder into common shares of the Company at a conversion price of $2.91 per share until maturity and bore interest at a rate of 8.0% per annum.
The premium related to the conversion was determined to be $3,813, which was recognized in equity as part of additional paid-in capital. The remainder of the proceeds of $56,187 was allocated to the debt component of the Convertible Promissory Note. The debt component was accreted to the principal balance over its estimated life. The Company incurred accretion expense of $65 and $3,052 for the years ended December 31, 2024 and 2023.
During the year ended December 31, 2024, the Company incurred interest expense of $1,735.
In February 2024, the debt was converted to equity by the issuance of 6,872,143 common shares to the debt holder.
16.Related Party Transactions
Related parties include key management of the Company and any entities controlled by these individuals or their direct family members. Key management personnel consist of directors and senior management including the Executive Chairman, Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and General Counsel. Amounts paid to management personnel were immaterial for the years ended December 31, 2025 and 2024.
During the year ended December 31, 2025 the Company entered into several amendments to the Uranium Loan with Boss. On August 22, 2025 the Company repaid all outstanding amounts and terminated the Uranium Loan Agreement as discussed in Note 1 5 – Debt. Boss owns 30% of the JV Alta Mesa, as discussed in Note 8 - Sale of Minority Interest in Alta Mesa.
On April 8, 2025, the Company completed a sale of NM Energy Canada that holds the Crownpoint and Hosta Butte projects pursuant to a Purchase Agreement with Verdera. The spouse of the Company’s former Chairman, the Company’s former Chairman and certain directors of the Company serve as officers, members of the board of directors or advisors to Verdera and certain directors and officers of the Company own common shares of Verdera. The Audit Committee of the Board consisting solely of disinterested directors oversaw the negotiation of the terms of the sale on behalf of the Company. A third-party valuation firm acted as financial advisor to the Audit Committee and provided the Audit Committee with an opinion as to the fairness, from a financial point of view, to the Company of the consideration received in the sale pursuant to the purchase agreement. The purchase agreement was unanimously approved by the Board upon recommendation by the Audit Committee. For more information regarding the Sale, see Note 7 – Mineral Rights and Properties.
F-36

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
As of December 31, 2025, and December 31, 2024, the following amounts were owed to related parties:

|  | As of December 31,
|  | 2025 | 2024
5-Spot Corporation | Consulting services | $ | 12 |  | $ | 10 |
Powerhaus Gruppe Corp | Consulting services | 27 |  | - |
Officers and Board members | Accrued compensation | 1,021 |  | 836 |
Boss | Note payable including accrued interest | - |  | 21,639 |
Total |  | $ | 1,060 |  | $ | 22,485 |

17.Income Taxes
Net loss before income taxes was generated as follows:

|  | As of December 31,
|  | 2025 |  | 2024
Domestic - Canada |  | $ | (28,587) |  |  | $ | (21,525) |
Foreign – outside of Canada |  | (34,924) |  |  | (52,397) |
|  | $ | (63,511) |  |  | $ | (73,922) |

Income tax expense (benefit) is comprised of the following:

|  | As of December 31,
|  | 2025 |  | 2024
Current tax expense |  |  |  |
Domestic – Canada |  | $ | - |  |  | $ | - |
Foreign – outside of Canada |  | 108 |  |  | 38 |
|  | $ | 108 |  |  | $ | 38 |
Deferred tax benefit |  |  |  |
Domestic – Canada |  | $ | - |  |  | $ | - |
Foreign – outside of Canada |  | (596) |  |  | (5,967) |
|  | $ | (596) |  |  | $ | (5,967) |
Income tax benefit |  | $ | (488) |  |  | $ | (5,929) |

F-37

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
The amounts of income tax paid, net of tax refunds received, are as follows:

|  | As of December 31,
|  | 2025 |  | 2024
Domestic – Canada |  | 0 |  | 0
Foreign – outside of Canada |  | 108 |  | 38
|  | 108 |  | 38

A reconciliation of income tax benefit (expense) to the amount computed by applying the 15% Canadian federal income tax rate after the adoption of ASU 2023-09 is presented below. The Canadian federal income tax rate is utilized as the Company's income tax filing entity is a Canadian corporation that is domiciled in Canada.

|  | As of December 31, |
|  | 2025 |  | 2024
Loss before tax |  | $ | (63,511) |  |  |  | $ | (73,922) |  |
Canadian Federal income tax |  | (9,527) |  | 15.00 | % |  | (11,088) |  | 15.00 | %
Nontaxable or nondeductible items |  |  |  |  |  |
Share-based payment awards |  | 630 |  | (0.99) | % |  | 729 |  | (0.99) | %
Non-taxable portion of capital gains |  | (1,562) |  | 2.46 | % |  | - |  | - | %
Other |  | 264 |  | (0.42) | % |  | 41 |  | (0.05) | %
Cross-border taxes |  | - |  | - | % |  | - |  | - | %
Changes in valuation allowances |  | 4,713 |  | (7.42) | % |  | 2,312 |  | (3.13) | %
Other |  | (112) |  | 0.18 | % |  | (14) |  | 0.02 | %
Foreign tax effects |  |  |  |  |  |
Statutory tax rate difference between United States and Canada |  | (2,426) |  | 3.82 | % |  | (3,678) |  | 4.98 | %
Nontaxable or nondeductible items |  | 240 |  | (0.38) | % |  | - |  | - | %
Tax rate differences and tax rate changes |  | - |  | - | % |  | 552 |  | (0.75) | %
Non-controlling interest |  | 1,091 |  | (1.72) | % |  | 1,345 |  | (1.82) | %
Changes in valuation allowances |  | 3,786 |  | (5.96) | % |  | 4,217 |  | (5.70) | %
Deferred only adjustment |  | 1,576 |  | (2.48) | % |  | - |  | - | %
Other |  | 484 |  | (0.76) | % |  | (507) |  | 0.68 | %
Tax rate differences and tax rate changes |  | 355 |  | (0.56) | % |  | 162 |  | (0.22) | %
Canadian provincial income tax |  | - |  | - | % |  |  | - | %
Income tax benefit |  | $ | (488) |  | 0.77 | % |  | $ | (5,929) |  | 8.02 | %

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
F-38

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)

|  | December 31,
|  | 2025 |  | 2024
Deferred tax assets: |  |  |  |
Loss carryforwards |  | $34,024 |  | $24,983
Mineral rights and properties |  | 3,363 |  |  | 4,952 |
Inventory |  | - |  |  | 1,489 |
Transaction and financing costs |  | 920 |  |  | 1,685 |
Lease liability |  | 881 |  |  | 97 |
Warranty liability |  | 815 |  |  | 815 |
Investment in partnership |  | 4,039 |  |  | 3,066 |
Investments in equity and securities |  | 2,880 |  |  | - |
Restricted interest and financing expenses |  | 1,608 |  |  | - |
Other |  | 2,282 |  |  | 197 |
Deferred tax assets |  | 50,812 |  |  | 37,284 |
Valuation allowance |  | (46,906) |  |  | (34,697) |
Net deferred tax asset |  | 3,906 |  |  | 2,587 |
Deferred tax liabilities: |  |  |  |
Investments in equity securities |  | - |  |  | (786) |
Intangible assets |  | (31) |  |  | (35) |
Right of use of assets |  | (828) |  |  | (86) |
Mineral rights and properties |  | (28,162) |  |  | (28,142) |
Property, plant and equipment |  | (1,030) |  |  | - |
Other |  | (239) |  |  | (518) |
Deferred tax liabilities |  | (30,290) |  |  | (29,567) |
Deferred tax assets |  | 3,906 |  |  | 2,587 |
Net deferred tax liability | $ | $(26,384) |  | $(26,980)

Deferred income taxes have not been recorded on the basis differences for investments in consolidated subsidiaries as these basis differences are indefinitely reinvested or will reverse in a non-taxable manner. Quantification of the deferred income tax liability, if any, associated with indefinitely reinvested basis differences is not practicable.
A valuation allowance has been taken against the US federal and state deferred tax assets of $19,486. A valuation allowance has been taken against the Canadian deferred tax assets of $27,420.
The following table summarizes the changes to the valuation allowance:

For the Years Ended |  | Balance |  |  |  |  |  | Balance
December 31, |  | Beginning of Period |  | Additions (1) |  | Deductions (2) |  | End of Period
2025 |  | $ | 34,697 |  |  | $ | 19,065 |  |  | $ | (6,856) |  |  | $ | 46,906 |
2024 |  | $ | 24,819 |  |  | $ | 12,138 |  |  | $ | (2,260) |  |  | $ | 34,697 |

(1) The additions to the valuation allowance during the year ended December 31, 2025 result from the generation of additional tax losses as well as increases to tax assets such as mineral property and inventory. The additions to the valuation allowance during the year ended December 31, 2024 result from the generation of additional tax losses and deferred tax assets acquired from Base Resources.
F-39

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
(2) The reductions to the valuation allowance during the year ended December 31, 2025 result from the decrease to tax assets such as debt issuance costs, property, plant and equipment and asset retirement obligations. For the year ended December 31, 2024, the reductions to the valuation allowance result from the decrease to tax assets such as ARO and mineral properties in the U.S.
The following table summarizes the Company’s capital losses and net operating losses as of December 31, 2025 that can be applied against future taxable income:

Country |  | Type |  | Amount |  | Expiry Date
Canada |  | Non-capital losses |  | $ | 80,542 |  |  | Between 2028 and 2045
Canada |  | Investment tax credits |  | - |  |  |
United States |  | Expiring loss (Federal and state) |  | 32,291 |  |  | Between 2028 and 2044
United States |  | Non-Expiring loss (Federal and state) |  | 56,810 |  |  | No expiration
Total |  |  |  | $ | 169,643 |  |  |

Under Section 382 of the Internal Revenue Code of 1986, a corporation that undergoes an ownership change is subject to limitation on its use of pre-change tax attributes and carryforward to offset future taxable income. At December 31, 2025 and 2024, the historical section 382 federal net operating loss limitation for certain subsidiaries is $11,302.
In addition, as a result of the Tax Cuts and Jobs Act, U.S. net operating loss carryforwards generated after December 31, 2017 are limited to usage at 80% of taxable income and will be permitted to be carried forward indefinitely.
Utilization of the Canadian loss carry forwards will be subject to the Acquisition of Control Rules in any year as a result of previous changes in ownership.
The Company files income tax returns in the U.S. federal and various state jurisdictions with varying statutes of limitations. The Company’s net operating losses from all years may be subject to adjustment for three or four years following the year in which utilized. We do not anticipate that any potential tax adjustments will have a significant impact on our financial position or results of operations.
The Company’s policy is to include interest and penalties related to uncertain tax positions in the income tax expense line on the financial statements. As of December 31, 2025, the Company does not have any uncertain tax positions.
For the year ended December 31, 2025, the Company recorded income tax benefit of $0.5 million on loss before tax of $63.5 million. For the year ended December 31, 2024, the Company recorded income tax benefit of $5.9 million on loss before tax of $73.9 million. For the year ended December 31, 2023, the Company recorded income tax benefit of $0.5 million on loss before tax of $26.1 million. The effective tax rate was 0.77%, and 8.02% for the years ended December 31, 2025 and 2024, respectively.
18.Segments
The Company’s operations are located in the United States and are organized into a single reportable segment and its sole business is the extraction, recovery and sales of uranium from mineral properties along with the exploration, permitting and evaluation of uranium properties in the United States. All of the Company’s assets are held in the United States. This segment has been identified based on the way the CODM assesses the business and allocates resources. This segment is monitored for performance and is consistent with internal financial reporting.
The CODM evaluates segment performance and allocates resources using financial information on a basis consistent with the Company’s consolidated financial statements. The significant segment expense information reviewed by the CODM are those presented on the accompanying consolidated statements of operations. The CODM evaluates the performance of the Company’s reportable segment based on income (loss) from operations,
F-40

enCore Energy Corp.
Notes to Consolidated Financial Statements
(all amounts in thousands, except for shares)
which is also what is reported on the consolidated statement of operations. The measure of segment assets is reported on the accompanying consolidated balance sheets as total consolidated assets.
The accounting policies of the segment are the same as those described in Note 2. Summary of Significant Accounting Policies.
Revenues from three external customers accounted for all of the Company’s total revenues during the period, each of which individually accounted for 10% or more the Company’s total revenues. Revenues from these customers were $27,231, $10,980, and $4,944, respectively. All such revenues are attributable to the Company’s single reportable segment.
19.Subsequent Events
On February 20, 2026, Verdera announced POCML 7 Inc. acquired all issued and outstanding common shares of Verdera and as a result of such qualifying transaction, the resulting issuer was renamed Verdera Energy Corp. (“Resulting Verdera”) and listed on the TSX-V. The initial public offering resulted in the conversion of 15,000,000 non-voting preferred shares to common shares that the Company was issued as part of the NM Energy Canada Share Purchase Agreement. The shares issued are valued at $27,010. As a result of the IPO, the conditions associated with the Company’s transaction involving NME satisfied the Going Public Transaction, and the transaction is now accounted for as a sale rather than a financing arrangement, resulting in the derecognition of the NM Energy Canada assets and liabilities and recognition of the consideration received and any resulting gain or loss. Since the IPO occurred after the balance sheet date, the accounting for the sale is not reflected in the financial statements as of December 31, 2025. The Company and Resulting Verdera entered into a Side Letter, dated March 31, 2026, to confirm the acquisition by POCML 7 Inc. and subsequent listing of Resulting Verdera’s common stock on the TSX-V satisfied the Going Public Transaction requirement pursuant to the Share Purchase Agreement.
During February 2026, holders of previously issued warrants exercised approximately 6.6 million warrants, providing approximately $18.1 million cash to the Company.
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Table of Contents
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our management, with the participation of our principal executive officer (“CEO”) and principal financial officer (“CFO”), evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2025. Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. We believe, however, that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls systems are met, and because of the inherent limitations of any system of controls, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
Based on management’s evaluation, our CEO and CFO concluded that our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2025 because of material weaknesses in internal control over financial reporting described below.
Notwithstanding such material weaknesses in our internal control over financial reporting, our management, including our CEO and CFO, considered the remediation activities described below, operational testing of the remediated controls, and the impact of such controls and believes that the consolidated financial statements included in this Annual Report present fairly, in all material respects, our financial position, results of operations and cash flows as of and for the periods presented, in accordance with those principles.
Management’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed under the supervision of our CEO and CFO, overseen by our Board of Directors and its Audit Committee, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Management assessed the effectiveness of the Company’s internal control over financial reporting using the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Based on our assessment under the criteria described above, management has concluded that our internal control over financial reporting was not effective at a reasonable assurance level as of December 31, 2025 because of material weaknesses described below.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that compliance with policies or procedures may deteriorate.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of annual or interim financial statements will not be prevented or detected on a timely basis.
As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024, management identified material weaknesses as of December 31, 2024 related to (i) ineffective general information technology controls (“GITCs”) over systems relevant to financial reporting and (ii) ineffective design, implementation, and operation of certain process level control activities. These deficiencies were primarily attributable to an ineffective control environment that resulted in ineffective risk assessment, information and communication, and monitoring activities, including an insufficient number of trained resources with appropriate expertise and responsibility for internal control over financial reporting and information technology. The previously identified deficiencies did not result in a material misstatement of our consolidated financial statements; however, management concluded that these deficiencies constituted material weaknesses in internal control over financial reporting as of December 31, 2024.
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Table of Contents
During 2025, the Company began the execution of a comprehensive remediation program and has made substantial progress on the design and implementation of controls necessary to address the identified material weaknesses, including hiring key highly qualified personnel with deep experience in internal control over financial reporting.
Management continued the execution of this remediation program subsequent to year end and as of the date of this filing:
•Management has designed, implemented, and placed into operation key control activities;
•Management has remediated user access roles and segregation of duties conflicts within core financial systems;
•Management has formalized, documented, and assigned ownership of key financial reporting controls;
•A substantial portion key controls have operated for at least one full reporting cycle;
•A substantial portion of key controls tested to date have operated effectively with no identified exceptions;
•The Company has achieved a disciplined financial close process, including timely execution of account reconciliations, journal entry controls, and management review controls across all significant accounts; and
•Financial processes have been integrated into a controlled ERP environment with system-enforced workflows and audit trails.
These actions have significantly enhanced the Company’s control environment and addressed the underlying root causes of the previously identified material weaknesses.
As a smaller reporting company and non-accelerated filer, the Company is not required to obtain, and our independent registered public accounting firm did not perform an audit of internal control over financial reporting as of December 31, 2025.
Changes in Internal Control over Financial Reporting
During the year ended December 31, 2025, the Company implemented significant changes to its internal control over financial reporting as part of its remediation program, including enhancements to GITCs, financial close processes, and system-based controls.
These changes have materially strengthened the Company’s internal control framework and are expected to support the final validation of remediation.
Other than the remediation activities described above, there was no change in our internal control over financial reporting during the quarter ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Adoption or Termination of Insider Trading Arrangements.
On December 17, 2025, Susan Hoxie-Key, a director of the Company, adopted a stock trading plan intended to satisfy the affirmative defense of Rule 10b5-1(c) of the Exchange Act under which an aggregate of up to 61,297 common shares issued upon vesting of restricted stock units may be sold. The plan is effective beginning on October 8, 2026 and will terminate on the earlier of the date all the shares covered by the plan are sold and October 8, 2028.
On March 31, 2026, the Company and Verdera entered into a Side Letter pursuant to which the Company and Verdera agreed that the qualifying transaction between POCML 7 Inc. and Verdera, which resulted in the resulting issuer, Verdera Energy Corp. (formerly POCML 7 Inc.) becoming listed on the TSX-V, satisfied the Going Public Transaction condition pursuant to the Share Purchase Agreement, subject to survival of certain covenants and representations and warranties related to, among other things, filing a resale registration statement for the Company’s intended distribution of common shares of the resulting issuer to the Company’s shareholders by way of stock dividend or similar distribution.
43

Table of Contents
T he Company owns 900,000 common shares (approximately 7.2% of the issued and outstanding shares on a fully diluted basis) of Group 11 Technologies Inc. (“Group 11”), a private mineral exploration company. Shareholders of Group 11, including the Company, entered into a Share Exchange Agreement (the “Exchange Agreement”) with Group 11 and Manhattan Metals Corp. (“Manhattan Metals”) on March 27, 2026, pursuant to which Manhattan Metals purchased each common share of Group 11 in exchange for 1.5 common shares of Manhattan Metals. The Exchange Agreement contains representations and warranties of the parties customary for transactions of this type. The former Executive Chairman and current Chairman Emeritus of the Company and his spouse are directors of Group 11 and Manhattan Minerals and his spouse is president of Group 11 and Manhattan Minerals.
Item 9C Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
None
44

Table of Contents
Part III
Item 10. Directors, Executive Officers and Corporate Governance
The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 11. Executive Compensation
The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 12. Security Ownership of Certain Beneficial Owner and Management and Related Stockholder Matters
The information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 14. Principal Accountant Fees and Services
The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.
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Table of Contents
Part IV
Item 15. Exhibits, Financial Statement Schedules
(1) Financial Statements

| Page Number
Report of Independent Registered Public Accounting Firm |
Consolidated Balance Sheets as of December 31, 2025 and 2024 |
Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2025 and 2024 |
Consolidated Statements of Changes in Equity for the years ended December 31, 2025 and 2024 |
Consolidated Statements of Cash Flows for the years ended December 31, 2025 and 2024 |
Notes to the Consolidated Financial Statements |

(2) Financial Statement Schedules
Schedules are omitted and are not applicable or not required, or the required information is shown in the financial statements or notes thereto.
(3) Exhibits
Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses.

Exhibit | Description
3.1 | Articles of enCore Energy Corp., as amended on November 6, 2024 (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
4.1 | Description of Securities (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
4.2 | Indenture (including Form of Note) with respect to enCore Energy Corp.’s 5.50% Convertible Senior Notes due 2030, dated August 22, 2025, by and between enCore Energy Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 22, 2025)
4.3 | Warrant Indenture - February 2023 (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
4.4 | Warrant Indenture - December 2022 (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
4.5 | Warrant Indenture - March 2022 (incorporated by reference to Exhibit 4.4 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
4.6 | Warrant Indenture - March 2021 (incorporated by reference to Exhibit 4.5 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
4.7 | Warrant Indenture - October 2020 (incorporated by reference to Exhibit 4.6 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
10.1+ | Stock Option Plan (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed with the SEC on July 7, 2023)
10.2+ | enCore Energy Corp. 2024 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
10.3 | Share Purchase Agreement, dated March 17, 2025, by and among enCore Energy Corp., Verdera Energy Corp. and NM Energy Holding Canada Corp. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 18, 2025)
10.4+ | Letter Agreement, dated April 3, 2025, by and between Robert Willette and enCore Energy Corp. (incorporated by reference to the Company’s Current Report on Form 8-K filed with the SEC on April 7, 2025)
10.5 | Side Letter, dated April 4, 2025, by and between enCore Energy Corp. and Verdera Energy Corp. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 9, 2025)
10.6 | Registration Rights Agreement, executed April 8, 2025, by and between enCore Energy Corp. and Verdera Energy Corp. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on April 9, 2025)

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10.7 | Side Letter, dated November 25, 2025, by and between enCore Energy Corp. and Verdera Energy Corp. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 2, 2025)
10.12+ | Confidential Settlement and General Release Agreement, dated October 10, 2025, by and between URI, Inc. and William Paul Goranson (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 17, 2025)
10.13 | Form of Capped Call Confirm (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 22, 2025)
10.14* | Amended and Restated Limited Liability Company Agreement, dated December 5, 2023, by and between enCore Energy Corp. and Boss Energy Limited
10.15+ | 2024 LTIP Non-employee Director Stock Option Form Award Agreement (before September 2025) (incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
10.16+ | 2024 LTIP Employee Incentive Stock Option Form Award Agreement (before September 2025) (incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
10.17*+ | Non-Employee Director Stock Option Form Award Agreement (after September 2025)
10.18*+ | Employee Incentive Stock Option Form Award Agreement (after September 2025)
10.19*+ | Form of Director Restricted Stock Unit Award Agreement (after September 2025)
10.20*+ | Form of Executive Restricted Stock Unit Award Agreement (after September 2025)
10.21+ | Employment Agreement (William B. Sheriff) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on September 25, 2025)
10.22+ | Employment Agreement (Robert Willette) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 25, 2025)
10.23+ | Employment Agreement (Dain McCoig) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 29, 2025)
10.24+ | Employment Agreement (Kevin Kremke) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 10, 2025)
10.26+ | Transition Services, Separation and General Release Agreement, by and between Shona Wilson and URI, Inc. dated July 28, 2025 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 29, 2025)
19.1 | Insider Trading Policy (incorporated by reference to Exhibit 19 to the Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2025)
21.1* | List of Subsidiaries
23.1* | Consent of KPMG LLP
23.2* | Consent of Ray Moores, P.E.
23.3* | Consent of Christopher McDowell P.G.
23.4* | Consent of SOLA Project Services LLC
31.1* | Certification of the Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the U.S. Securities Exchange Act of 1934
31.2* | Certification of the Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the U.S. Securities Exchange Act of 1934
32.1** | Certification of Principal Executive Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
96.1 | Technical Report on the South Texas Integrated Uranium Projects in Texas, USA, effective December 31, 2024 (incorporated by reference to Exhibit 96.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 27, 2025)
96.2 | Economic Assessment Technical Report for the Gas Hills Uranium Project in Fremont and Natrona Counties, Wyoming, USA, effective date of December 31, 2024 (incorporated by reference to Exhibit 96.2 to the Company’s Current Report on Form 8-K filed with the SEC on February 27, 2025)
96.3 | Technical Report on the Alta Mesa Uranium Projects in Texas, USA, effective December 31, 2024 (incorporated by reference to Exhibit 96.3 to the Company’s Current Report on Form 8-K filed with the SEC on February 27, 2025)
96.4 | Technical Report Summary for the Dewey Burdock Project effective October 8, 2024 (incorporated by reference to Exhibit 96.1 of our Current Report on Form 8-K, filed on January 16, 2025)
96.5 | Technical Report Summary Initial Assessment on the Mesteña Grande Uranium Project, Brooks and Jim Hogg Counties, Texas, USA, dated February 19, 2025 and effective as of December 31, 2024 (incorporated by reference to Exhibit 96.4 to the Company’s Current Report on Form 8-K filed with the SEC on February 27, 2025)

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97.1 | Incentive Compensation Recovery Policy(incorporated by reference to Exhibit 97 to the Company’s Form 40-F, filed with the SEC on March 28, 2024)
101 | Interactive Data File (formatted as iXBRL)
101.INS* | Inline XBRL Instance Document
101.SCH* | Inline XBRL Taxonomy Extension Schema Document
101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document
104* | Cover Page Interactive Data File (formatted as iXBRL and contained in Exhibit 101)

* Filed herewith.
** Furnished herewith.
+ Management contract, compensatory plan or other arrangement.
Item 16. Form 10-K Summary
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

| ENCORE ENERGY CORP.
| /s/ Robert Willette
March 31, 2026 | Robert Willette
| Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature |  | Date
/s/ Robert Willette | Chief Executive Officer and Director (Principal Executive Officer) | March 31, 2026
Robert Willette |  |
/s/ Kevin Kremke | Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | March 31, 2026
Kevin Kremke |
/s/ Wayne W. Heili | Director | March 31, 2026
Wayne W. Heili |  |
/s/ William B. Harris | Director | March 31, 2026

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William B. Harris |  |
/s/ Susan Hoxie-Key | Director | March 31, 2026
Susan Hoxie-Key |  |
/s/ Nathan Tewalt | Director | March 31, 2026
Nathan Tewalt |  |
/s/ Mark Pelizza | Director | March 31, 2026
Mark Pelizza |  |

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