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United States

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

(Mark One)

 

 

 

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

 

FOR THE FISCAL YEAR ENDED December 31, 2016

 

 

 

 

 

 

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: 001-33905

 

UR-ENERGY INC.

(Exact name of registrant as specified in its charter)

 

 

 

Canada

Not Applicable

State or other jurisdiction of incorporation or organization

(I.R.S. Employer Identification No.)

 

10758 West Centennial Road, Suite 200
Littleton, Colorado 80127
(Address of principal executive offices, including zip code)

 

Registrant’s telephone number, including area code: 720-981-4588

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

Title of each class

Name of each exchange on which registered

Common Shares, no par value

NYSE MKT

 

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 ☐No ☑

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act.  

Yes ☐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 ☑No ☐

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

Yes ☑   No ☐

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or smaller reporting company:

 

Large accelerated filer ☐                     Accelerated filer ☑               Non-accelerated filer ☐             Smaller reporting company ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐No ☑

 

As of March 2, 2017, there were 145,616,297 shares of the registrant’s no par value Common Shares (“Common Shares”), the registrant’s only outstanding class of voting securities, outstanding. As of June 30, 2016, the aggregate market value of the registrant’s voting Common Shares held by non-affiliates of the registrant was approximately $72.4 million based upon the closing sale price of the Common Shares as reported by the NYSE MKT. For the purpose of this calculation, the registrant has assumed that its affiliates as of June 30, 2016, included all directors and officers and two shareholders that held approximately 21.5 million of its outstanding Common Shares. 

 

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required for Items 10, 11, 12, 13 and 14 of Part III of this Annual Report on Form 10-K is incorporated by reference to the registrant’s definitive proxy statement for the 2017 Annual Meeting of Shareholders.

 

 

 


 

Table of Contents

UR-ENERGY INC.

ANNUAL REPORT ON FORM 10-K

 

TABLE OF CONTENTS

 

 

 

 

 

 

 

Page

 

PART I

 

 

 

 

Items 1 and 2. 

Business and Properties

8

Item 1A. 

Risk Factors

28

Item 1B. 

Unresolved Staff Comments

36

Item 3. 

Legal Proceedings

36

Item 4. 

Mine Safety Disclosure

36

 

 

 

 

PART II

 

 

 

 

Item 5. 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

37

Item 6. 

Selected Financial Data

41

Item 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

42

Item 7A. 

Quantitative and Qualitative Disclosures about Market Risk

64

Item 8. 

Financial Statements and Supplementary Data

69

Item 9. 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

69

Item 9A. 

Controls and Procedures

69

Item 9B. 

Other Information

70

 

 

 

 

PART III

 

 

 

 

Item 10. 

Directors, Executive Officers and Corporate Governance

71

Item 11. 

Executive Compensation

71

Item 12. 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

71

Item 13. 

Certain Relationships and Related Transactions, and Director Independence

71

Item 14. 

Principal Accounting Fees and Services

71

 

 

 

 

PART IV

 

 

 

 

Item 15. 

Exhibits, Financial Statement Schedules

72

 

Signatures

75

 

 

 

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When we use the terms “Ur-Energy,” “we,” “us,” “our,” or the “Company” we are referring to Ur-Energy Inc. and its subsidiaries, unless the context otherwise requires. We have included technical terms important to an understanding of our business under “Glossary of Common Terms” at the end of this section. 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.

 

Cautionary Statement Regarding Forward-Looking Information

 

This annual report on Form 10-K contains "forward-looking statements" within the meaning of applicable United States and Canadian securities laws, and these forward-looking statements can be identified by the use of words such as "expect," "anticipate," "estimate," "believe," "may," "potential," "intends," "plans" and other similar expressions or statements that an action, event or result "may," "could" or "should" be taken, occur or be achieved, or the negative thereof or other similar statements. These statements are only predictions and involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance or achievements, or industry results, to be materially different from any future results, performance, or achievements expressed or implied by these forward-looking statements. Such statements include, but are not limited to: (i) the ability to maintain steady state operations at Lost Creek and timing to determine future development and construction priorities; (ii) the technical and economic viability of Lost Creek; (iii) the timing and outcome of permitting and regulatory approvals of the amendment for LC East and the KM horizon; (iv) the ability to complete additional favorable uranium sales agreements including spot sales if the market warrants and production inventory is available; (v) the production rates and life of the Lost Creek Project and subsequent production from adjoining properties, including LC East; (vi) the potential of exploration targets throughout the Lost Creek Property (including the ability to expand resources); (vii) the potential of our other exploration and development projects, including Shirley Basin, as well as the technical and economic viability of Shirley Basin; (viii) the timing and outcome of applications for regulatory approval to build and operate an in situ recovery (“ISR”) mine at Shirley Basin; (ix) the outcome of our forecasts and production projections; and (x) the continuing and long-term effects on the uranium market of events in Japan in 2011 including supply and demand projections. These other factors include, among others, the following: future estimates for production, development and production ramp-up and operations, capital expenditures, operating costs, mineral resources, recovery rates, grades and market prices; business strategies and measures to implement such strategies; competitive strengths; estimates of goals for expansion and growth of the business and operations; plans and references to our future successes; our history of operating losses and uncertainty of future profitability; status as an exploration stage company; the lack of mineral reserves; risks associated with obtaining permits and other authorizations in the United States; risks associated with current variable economic conditions; our ability to service our debt and maintain compliance with all restrictive covenants related to the debt facilities and security documents; the possible impact of future financings; the hazards associated with mining production; compliance with environmental laws and regulations; uncertainty regarding the pricing and collection of accounts; the possibility for adverse results in potential litigation; uncertainties associated with changes in government policy and regulation; uncertainties associated with a Canada Revenue Agency or U.S. Internal Revenue Service audit of any of our cross border transactions; adverse changes in general business conditions in any of the countries in which we do business; changes in size and structure; the effectiveness of management and our strategic relationships; ability to attract and retain key personnel; uncertainties regarding the need for additional capital; uncertainty regarding the fluctuations of quarterly results; foreign currency exchange risks; ability to enforce civil liabilities under U.S. securities laws outside the United States; ability to maintain our listing on the NYSE MKT LLC (“NYSE MKT”) and Toronto Stock Exchange (“TSX”); risks associated with the expected classification as a "passive foreign investment company" under the applicable provisions of the U.S. Internal Revenue Code of 1986, as amended; risks associated with our investments and other risks and uncertainties described under the heading “Risk Factors” of this annual report.

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Cautionary Note to U.S. Investors Concerning Disclosure of Mineral Resources

 

Unless otherwise indicated, all resource estimates included in this Form 10-K have been prepared in accordance with Canadian National Instrument 43-101 Standards of Disclosure for Mineral Projects (“NI 43-101”) and the Canadian Institute of Mining, Metallurgy and Petroleum Definition Standards for Mineral Resources and Mineral Reserves (“CIM Definition Standards”). NI 43-101 is a rule developed by the Canadian Securities Administrators which establishes standards for all public disclosure an issuer makes of scientific and technical information concerning mineral projects. NI 43-101 permits the disclosure of an historical estimate made prior to the adoption of NI 43-101 that does not comply with NI 43-101 to be disclosed using the historical terminology if the disclosure: (a) identifies the source and date of the historical estimate; (b) comments on the relevance and reliability of the historical estimate; (c) to the extent known, provides the key assumptions, parameters and methods used to prepare the historical estimate; (d) states whether the historical estimate uses categories other than those prescribed by NI 43-101; and (e) includes any more recent estimates or data available. 

 

Canadian standards, including NI 43-101, differ significantly from the requirements of the United States Securities and Exchange Commission (“SEC”), and resource information contained in this Form 10-K may not be comparable to similar information disclosed by U.S. companies. In particular, the term “resource” does not equate to the term “‘reserves.” Under SEC Industry Guide 7, mineralization may not be classified as a “reserve” unless the determination has been made that the mineralization could be economically and legally produced or extracted at the time the reserve determination is made. SEC Industry Guide 7 does not define and the SEC’s disclosure standards normally do not permit the inclusion of information concerning “measured mineral resources,” “indicated mineral resources” or “inferred mineral resources” or other descriptions of the amount of mineralization in mineral deposits that do not constitute “reserves” by U.S. standards in documents filed with the SEC. U.S. investors should also understand that “inferred mineral resources” have a great amount of uncertainty as to their existence and great uncertainty as to their economic and legal feasibility. It cannot be assumed that all or any part of an “inferred mineral resource” will ever be upgraded to a higher category. Under Canadian rules, estimated “inferred mineral resources” may not form the basis of feasibility or pre-feasibility studies except in rare cases. Investors are cautioned not to assume that all or any part of an “inferred mineral resource” exists or is economically or legally mineable. Disclosure of “contained ounces” in a resource is permitted disclosure under Canadian regulations; however, the SEC normally only permits issuers to report mineralization that does not constitute “reserves” by SEC standards as in-place tonnage and grade without reference to unit measures. Accordingly, information concerning mineral deposits set forth herein may not be comparable to information made public by companies that report in accordance with U.S. standards.

 

NI 43-101 Review of Technical Information: James A. Bonner, Ur-Energy Vice President Geology, P.Geo. and Qualified Person as defined by NI 43-101, reviewed and approved the technical information contained in this Annual Report.

 

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Glossary of Common Terms and Abbreviations

 

 

 

Mineral Resource 

is a concentration or occurrence of solid 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 eventual economic extraction. The location, quantity, grade or quality, continuity and other geological characteristics of a Mineral Resource are known, estimated or interpreted from specific geological evidence and knowledge, including sampling. CIM Definition Standards; NI 43-101, Section 1.1.

 

 

Inferred Mineral Resource

is that part of a Mineral Resource for which quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. Geologic evidence is sufficient to imply but not verify geological and grade or quality continuity. An Inferred Mineral Resource has a lower level of confidence than that applying to an Indicated Mineral Resource and must not be converted to a Mineral Reserve. It is reasonably expected that the majority of Inferred Mineral Resources could be upgraded to Indicated Mineral Resources with continued exploration.  CIM Definition Standards; NI 43-101, Section 1.1.

 

 

Indicated Mineral Resource

is that part of a Mineral Resource for which quantity, grade or quality, densities, shape and physical characteristics are estimated with sufficient confidence to allow the application of Modifying Factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. Geological evidence is derived from adequately detailed and reliable exploration, sampling and testing and is sufficient to assume geological and grade or quality continuity between points of observation. An Indicated Mineral Resource has a lower level of confidence than that applying to a Measured Mineral Resource and may only be converted to a Probable Mineral Reserve. CIM Definition Standards; NI 43-101, Section 1.1.

 

 

Measured Mineral Resource

is that part of a Mineral Resource for which quantity, grade or quality, densities, shape, and physical characteristics are estimated with confidence sufficient to allow the application of Modifying Factors to support detailed mine planning and final evaluation of the economic viability of the deposit. Geological evidence is derived from detailed and reliable exploration, sampling and testing and is sufficient to confirm geological and grade or quality continuity between points of observation. A Measured Mineral Resource has a higher level of confidence than that applying to either an Indicated Mineral Resource or an Inferred Mineral Resource. It may be converted to a Proven Mineral Reserve or to a Probable Mineral Reserve. CIM Definition Standards; NI 43-101, Section 1.1.

 

 

 

 

Cut-off or cut-off grade

when determining economically viable mineral resources, the lowest grade of mineralized material that can be mined

 

 

Formation

a distinct layer of sedimentary or volcanic rock of similar composition

 

 

Grade

 

Quantity or percentage of metal per unit weight of host rock

 

 

Host Rock

 

the rock containing a mineral or an ore body

 

 

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Modifying Factors

are considerations used to convert Mineral Resources to Mineral Reserves. These include, but are not restricted to, mining, processing, metallurgical, infrastructure, economic, marketing, legal, environmental, social and governmental factors. CIM Definition Standards

 

 

Lithology

is a description of a rock; generally, its physical nature. The description would address such things as grain size, texture, rounding, and even chemical composition. A lithologic description would be: coarse grained well rounded quartz sandstone with 10% pink feldspar and 1% muscovite.

 

 

Mineral

a naturally formed chemical element or compound having a definite chemical composition and, usually, a characteristic crystal form.

 

 

Mineralization

a natural occurrence, in rocks or soil, of one or more metal yielding minerals

 

 

Outcrop

is that part of a geologic formation or structure that appears at the surface of the Earth.

 

 

PFN 

is a modern geologic logging method known as Prompt Fission Neutron. PFN is considered a direct measurement of true uranium concentration (% U) and is used to verify the grades of mineral intercepts previously reported by gamma logging. PFN logging is accomplished by a down-hole probe in much the same manner as gamma logs, however, only the mineralized interval plus a buffer interval above and below are logged.

 

 

Preliminary Economic Assessment (or PEA)

A Preliminary Economic Assessment performed under NI 43-101. A Preliminary Economic Assessment is a study, other than a prefeasibility study or feasibility study, which includes an economic analysis of the potential viability of mineral resources.

 

 

 

Reclamation

is the process by which lands disturbed as a result of mineral extraction activities are modified to support beneficial land use. Reclamation activity may include the removal of buildings, equipment, machinery, and other physical remnants of mining activities, closure of tailings storage facilities, leach pads, and other features, and contouring, covering and re-vegetation of waste rock, and other disturbed areas.

 

 

Uranium

a heavy, naturally radioactive, metallic element of atomic number 92. Uranium in its pure form is a heavy metal. Its two principal isotopes are U-238 and U-235, of which U-235 is the necessary component for the nuclear fuel cycle. However, “uranium” used in this Annual Report refers to triuranium octoxide, also called “U3O8” or “yellowcake”, and is produced from uranium deposits. It is the most actively traded

uranium-related commodity.

 

 

Uranium concentrate

a yellowish to yellow-brownish powder obtained from the chemical processing of uranium-bearing material. Uranium concentrate typically contains 70% to 90% U3O8 by weight. Uranium concentrate is also referred to as “yellowcake.”

 

 

 

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Abbreviations:

 

 

BLM

U.S. Bureau of Land Management

CERCLA

Comprehensive Environmental Response and Liability Act

CIM

Canadian Institute of Mining, Metallurgy and Petroleum

DDW

Deep Disposal Well

eU3O8

Equivalent U3O8 as measured by a calibrated gamma instrument

EMT

East Mineral Trend, located within our LC East Project (Great Divide Basin, Wyoming)

EPA

U.S. Environmental Protection Agency

GDB

Great Divide Basin, Wyoming

GPM

Gallons per minute

GT

Grade x Thickness product (% ft.) of a mineral intercept (expressed without units)

HH

Header house

IX

Ion Exchange

ISR

In Situ Recovery (literally, ‘in place’ recovery) (also known as in situ leach or ISL)

LT

Long-term (as relates to long-term pricing in the uranium market)

MMT

Main Mineral Trend, located within our Lost Creek Project (Great Divide Basin, Wyoming)

MU

Mine Unit (also referred to as wellfield)

NEPA

U.S. National Environmental Policy Act

NI 43-101

Canadian National Instrument 43-101 (Standards of Disclosure for Mineral Properties)

NRC

U.S. Nuclear Regulatory Commission

PEA

Preliminary Economic Assessment

PPM

Parts per million

RCRA

Resource Conservation and Recovery Act

SEC

U.S. Securities Exchange Commission

UIC

Underground Injection Control (pursuant to U.S. Environmental Protection Agency regulations)

U3O8

A standard chemical formula commonly used to express the natural form of uranium mineralization.  U represents uranium and O represents oxygen.

URP

Wyoming Uranium Recovery Program (WDEQ Program name for Agreement State Program under development)

USFWS

U.S. Fish and Wildlife Service

WDEQ

Wyoming Department of Environmental Quality (and its various divisions, LQD/Land Quality Division, WQD/Water Quality Division; AQD/Air Quality Division; and SHWD/Solid and Hazardous Waste Division)

WEQC

Wyoming Environmental Quality Council

WGFD

Wyoming Game and Fish Department

 

Metric/Imperial Conversion Table

 

The imperial equivalents of the metric units of measurement used in this annual report are as follows:

 

 

 

 

 

 

Imperial Measure

Metric Unit

 Metric Unit

Imperial Measure

2.4711 acres

1 hectare

0.4047 hectares

1 acre

2.2046 pounds

1 kilogram

0.4536 kilograms

1 pound

0.6214 miles

1 kilometer

1.6093 kilometers

1 mile

3.2808 feet

1 meter

0.3048 meters

1 foot

1.1023 short tons

1 tonne

0.9072 tonnes

1 short ton

 

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Reporting Currency

 

All amounts in this report are expressed in United States (U.S.) dollars, unless otherwise indicated.  The Financial Statements are presented in accordance with accounting principles generally accepted in the United States.

 

PART  I

 

Items 1 and 2.  BUSINESS AND PROPERTIES

 

Overview and Corporate Structure

 

Incorporated on March 22, 2004, Ur-Energy is an exploration stage mining company, as that term is defined in Securities and Exchange Commission (“SEC”) Industry Guide 7.  We are engaged in uranium mining, recovery and processing activities, including the acquisition, exploration, development and operation of uranium mineral properties in the United States. We began operation of our first in situ recovery uranium mine at our Lost Creek Project, Wyoming in 2013. Ur-Energy is a corporation continued under the Canada Business Corporations Act on August 8, 2006. Our Common Shares are listed on the TSX under the symbol “URE” and on the NYSE MKT under the symbol “URG.”

 

Ur-Energy has one direct wholly-owned subsidiary: Ur-Energy USA Inc. (“Ur-Energy USA”), a company incorporated under the laws of the State of Colorado.

 

Ur-Energy USA has three wholly-owned subsidiaries: NFU Wyoming, LLC (“NFU Wyoming”), a limited liability company formed under the laws of the State of Wyoming to facilitate acquisition of certain property and assets and, currently, to act as our land holding and exploration entity; Lost Creek ISR, LLC, a limited liability company formed under the laws of the State of Wyoming to hold and operate our Lost Creek Project and certain other of our Lost Creek properties and assets; and Pathfinder Mines Corporation (“Pathfinder”), a company incorporated under the laws of the State of Delaware, which holds, among other assets, the Shirley Basin and Lucky Mc properties in Wyoming.

 

Ur-Energy USA has two jointly held subsidiaries with NFU Wyoming: NFUR Bootheel, LLC (“NFUR Bootheel”), a limited liability company formed under the laws of the State of Colorado to facilitate participation in an exploration, mining and development agreement with Jet Metal Corp.; and NFUR Hauber, LLC (“NFUR Hauber”), a limited liability company formed under the laws of the State of Colorado to facilitate participation in a venture project at our Hauber project.

 

NFUR Hauber has one wholly-owned subsidiary: Hauber Project LLC, a limited liability company formed under the laws of the State of Colorado to hold our Hauber project. NFUR Hauber is the sole member and manager of Hauber Project LLC.

NFUR Bootheel holds an interest in The Bootheel Project, LLC, a limited liability company formed under the laws of the State of Colorado to hold the Bootheel property (and, formerly, the Buck Point property), a venture with Jet Metal Corp., in which, at December 31, 2016, we own a 19.115% interest.

 

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Currently, and at December 31, 2016, our principal direct and indirect subsidiaries, and affiliated entities, and the jurisdictions in which they were incorporated or organized, are as follows:

 

Picture 1

 

We are engaged in uranium mining, recovery and processing operations, in addition to the exploration and development of uranium mineral properties. Our wholly-owned Lost Creek Project in Sweetwater County, Wyoming is our flagship property. The project has been fully permitted and licensed since October 2012. We received operational approval from the U.S. Nuclear Regulatory Commission (“NRC”), and started production operation activities in August 2013. Our first sales of production from Lost Creek were made in December 2013; and in the three years since, sales have been made in every quarter.

 

Currently, we have multiple term uranium sales agreements in place with U.S. utilities for the sale of Lost Creek production or other yellowcake product at contracted pricing. Combined, these multi-year sales agreements represent a significant portion of our anticipated production into 2021. These agreements, individually, do not represent a substantial portion of our annual projected production, and our business is therefore not substantially dependent upon any one of the agreements. 

 

The Company has contractually committed to sell 600,000 pounds of uranium yellowcake during 2017, at an average price of approximately $51 per pound. During 2016, we worked with our customers to establish our delivery schedule for these 2017 commitments, with distribution of sales throughout the year. This schedule was created in an attempt to avoid uneven cash flows that could result from uneven delivery schedules. Subsequently, we have taken advantage of the low prices at the end of 2016 and in early 2017 to enter into purchase agreements for 410,000 pounds at an average cost of $22 per pound. We have already delivered a portion of the pounds and can readily deliver the remaining pounds from our current inventory and anticipated production as detailed below.

 

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Our other material asset, Shirley Basin, is one of the assets we acquired as a part of the Pathfinder transaction which closed in December 2013. We also acquired all the historic geologic and engineering data for the project. During 2014, we completed a drill program of a limited number of confirmatory holes in order to complete an NI 43‑101 mineral resource estimate which was released in August 2014; subsequently, an NI 43‑101 Preliminary Economic Assessment for Shirley Basin was completed in January 2015. Baseline studies necessary for the permitting and licensing of the project commenced in 2014 and were completed in 2015. In December 2015, our application for a permit to mine was submitted to the State of Wyoming Department of Environmental Quality (“WDEQ”).

 

Work is well underway on other applications for all necessary authorizations to mine at Shirley Basin. We have monitored the development of the Wyoming “agreement state” program, by which the NRC will delegate its authority for source material licensure and other radiation safety issues to the WDEQ. We understand that the development of the Uranium Recovery Program (“URP”) remains on schedule for full implementation and transition likely occurring in 2018. Based upon that timing, we currently anticipate submitting our application for a source material license for Shirley Basin to the State URP.

We utilize in situ recovery of the uranium at Lost Creek and will do so at other projects where this is possible. The ISR technique is employed in uranium extraction because it allows for a lower cost and effective recovery of roll front mineralization. The in situ technique does not require the installation of tailings facilities or significant surface disturbance. This mining method utilizes injection wells to introduce a mining solution, called lixiviant, into the mineralized zone. The lixiviant is made of natural groundwater fortified with oxygen as an oxidizer, sodium bicarbonate as a complexing agent, and carbon dioxide for pH control. The complexing agent bonds with the uranium to form uranyl carbonate, which is highly soluble. The dissolved uranyl carbonate is then recovered through a series of production wells and piped to a processing plant where the uranyl carbonate is removed from the solution using Ion Exchange (“IX”) and captured on resin contained within the IX columns. The groundwater is re-fortified with the oxidizer and complexing agent and sent back to the wellfield to recover additional uranium. A low-volume bleed is permanently removed from the lixiviant flow. A reverse osmosis (RO) process is available to minimize the waste water stream generated. Brine from the RO process, if used, and bleed are disposed of by means of injection into deep disposal wells. Each wellfield is made up of dozens of injection and production wells installed in patterns to optimize the areal sweep of fluid through the uranium ore body.

 

Our Lost Creek processing facility includes all circuits for the capture, concentration, drying and packaging of uranium yellowcake for delivery into sales. Our processing facility, in addition to the IX circuit, includes dual processing trains with separate elution, precipitation, filter press and drying circuits (this is in contrast to certain other uranium in situ recovery facilities which operate as a capture plant only, and rely on agreements with other producers for the finishing, drying and packaging of their yellowcake end-product). Additionally, a restoration circuit including a RO unit was installed during initial construction to complete groundwater restoration once mining is complete.

 

The elution circuit (the first step after ion exchange) is utilized to transfer the uranium from the IX resin and concentrate it to the point where it is ready for the next phase of processing. The resulting rich eluate is an aqueous solution containing uranyl carbonate, salt and sodium carbonate and/or sodium bicarbonate. The precipitation circuit follows the elution circuit and removes the carbonate from the concentrated uranium solution and combines the uranium with peroxide to create a yellowcake crystal slurry. Filtration and washing is the next step, in which the slurry is loaded into a filter press where excess contaminants such as chloride are removed and a large portion of the water is removed. The final stage occurs when the dewatered slurry is moved to a yellowcake dryer, which will further reduce the moisture content, yielding the final dried, free-flowing, product. Refined, salable yellowcake is packaged in 55-gallon steel drums. 

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The restoration circuit may be utilized in the production as well as the post-mining phases of the operation. The RO may initially be utilized as a part of our Class V recycling circuit to minimize the waste water stream generated during production. Once production is complete, the groundwater must be restored to its pre-mining class of use by removing a small portion of the groundwater and disposing of it (commonly known as sweep). Following sweep, the groundwater is treated utilizing RO and re-injecting the clean water. Finally, the groundwater is homogenized and sampled to insure the cleanup is complete, thus ending the mining process.

 

Our Lost Creek processing facility was constructed during 2012 – 2013, with production operations commencing in August 2013. Our first sales were made in December 2013. Nameplate design and NRC-licensed capacity of our Lost Creek processing plant is two million pounds per year, of which approximately one million pounds per year may be produced from our wellfields. The Lost Creek plant and the allocation of resources to mine units and resource areas were designed to generate approximately one million pounds of production per year at certain flow rates and uranium concentrations subject to regulatory and license conditions. Production of refined yellowcake was 561,094 pounds and 727,245 pounds in 2016 and 2015, respectively. The excess capacity in the design of the processing circuits of the plant is intended, first, to facilitate routine (and, non-routine) maintenance on any particular circuit without hindering production operational schedules. The capacity was also designed to permit us to process uranium from other of our mineral projects in proximity to Lost Creek if circumstances warrant in the future (e.g., Shirley Basin Project), or, alternatively to be able to contract to toll mill/process product from other in situ uranium mine sites in the region. This design would permit us to conduct either of these activities while Lost Creek is producing and processing uranium and/or in years following Lost Creek production from wellfields during final restoration activities.

 

Our Lost Creek processing facility includes all circuits for the production, drying and packaging of uranium yellowcake for delivery into sales. As contemplated in the Preliminary Economic Assessment of Shirley Basin, we expect that the Lost Creek processing facility may be utilized for the drying and packaging of uranium from Shirley Basin, for which we currently anticipate the need only for a satellite plant. However, the Shirley Basin permit application contemplates the construction of a full processing facility, providing greater construction and operating flexibility as may be dictated by market conditions.

 

Our Mineral Properties

 

Our current land portfolio includes 13 projects in Wyoming. Ten of these projects are in the Great Divide Basin, Wyoming, including our flagship project, Lost Creek Project, which began production operations in August 2013. Currently we control more than 1,900 unpatented mining claims and three State of Wyoming mineral leases for a total of more than 37,500 acres (~15,500 hectares) in the area of the Lost Creek Property, including the Lost Creek permit area (the “Lost Creek Project” or “Lost Creek”) and certain adjoining properties which we refer to as LC East, LC West, LC North, LC South and EN project areas (collectively, with the Lost Creek Project, the “Lost Creek Property”). Five of the projects at the Lost Creek Property contain NI 43-101 compliant mineral resources: Lost Creek, LC East, LC West, LC South and LC North.  See Resource Summary below in

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Technical Developments. Below is a map showing our Wyoming projects and the geologic basins in which they are located.

 

\\ure-exchange\public\GIS\Presentations\2014\Penne_Feb\WY_PropLocations_20140228.jpg

 

Our Wyoming properties together total more than 55,000 acres (approximately 22,250 hectares) and include two properties, Shirley Basin and Lucky Mc, obtained through our acquisition of Pathfinder Mines Corporation in 2013.

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Operating Properties

 

Lost Creek Project – Great Divide Basin, Wyoming

 

The Lost Creek Project area was acquired in 2005, and is located in the Great Divide Basin, Wyoming. The Main Mineral Trend of the Lost Creek uranium deposit (the “MMT”) is located within the Lost Creek Project. The permit area of the Lost Creek Project covers 4,254 acres (1,722 hectares), comprising 201 lode mining claims and one State of Wyoming mineral lease section. Regional access relies almost exclusively on existing public roads and highways. The local and regional transportation network consists of primary, secondary, local and unimproved roads. Direct access to Lost Creek is mainly on two crown-and-ditched gravel paved access roads to the processing plant. One road enters from the west off of Sweetwater County Road 23N (Wamsutter-Crooks Gap Road); the other enters from the east off of U.S. Bureau of Land Management (“BLM”) Sooner Road. On a wider basis, from population centers, the Property area is served by an Interstate Highway (Interstate 80), a US Highway (US 287), Wyoming state routes (SR 220 and 73 to Bairoil), local county roads, and BLM roads. The Lost Creek Property is located as shown here:

 

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The basic infrastructure (power, water, and transportation) necessary to support our ISR operation is located within reasonable proximity. Generally, the proximity of Lost Creek to paved roads is beneficial with respect to transportation of equipment, supplies, personnel and product to and from the property. Existing regional

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overhead electrical service is aligned in a north-to-south direction along the western boundary of the Lost Creek Project. A new overhead power line, approximately two miles in length, was constructed to bring power from the existing Pacific Power line to the Lost Creek plant. Power drops have been made to the property and distributed to the plant, offices, wellfields, and other facilities. Additional power drops will be installed as we expand the wellfield operations.

 

Following the purchase of an existing production royalty with respect to 20 claims of the Lost Creek Project in 2013, there are no remaining royalties at the Lost Creek Project, except for the royalty on the State of Wyoming section mineral lease as provided by law. Currently, there is only limited production planned from the State lease section. There is a production royalty of one percent on certain claims of the LC East Project, and other royalties on other claims within the other adjoining projects (LC South and EN projects) as well as the other State sections on which we maintain mineral leases (LC West and EN projects).

 

Production Operations

 

Following receipt of the final regulatory authorization in October 2012, we commenced construction at Lost Creek. Construction included the plant facility and office building, installation of all process equipment, installation of two access roads, additional power lines and drop lines, deep disposal wells, construction of two holding ponds, warehouse building, and drill shed building.  In August 2013 we were given operational approval by the NRC and commenced production operation activities.  See also discussion of the operational methods used at Lost Creek, above, under heading “Business and Properties.”

 

For the Lost Creek PEA, in order to accurately reflect existing resources, all resources produced through September 30, 2015 (1,358,407 pounds) were subtracted from total Measured Resources from the HJ Horizon in Mine Unit 1 (“MU1”). All the wells to support the originally-planned 13 header houses (“HHs”) have been completed. HHs 1-1 through 1-11 were operational as of the effective date of the Lost Creek PEA, October 15, 2015. Subsequently, the last two of the originally-planned header houses were brought online (HH 1-12 (November 2015) and HH 1-13 (May 2016)).

 

All monitor ring wells have been installed and pump-tested in Mine Unit 2 (“MU2”). As of October 15, 2015, the effective date for the Lost Creek PEA, 138 pattern wells have been piloted within HHs 2-1, 2-2 and 2-3. Additionally, two applications for amendments to the license and permits have been submitted. The two applications seek to authorize production in the KM Horizon within the Lost Creek Project and to authorize production in the HJ and KM Horizons within the EMT in the LC East Project.

 

During 2016, 538,004 pounds of U3O8 were captured within the Lost Creek plant; 561,094 pounds U3O8  were packaged in drums; and 579,179 pounds U3O8  of drummed inventory were shipped from the Lost Creek processing plant to the converter. At December 31, inventory at the conversion facility was approximately 84,689 pounds U3O8

 

From production, Lost Creek sold 562,000 pounds U3O8  during calendar 2016 at an average price of $39.49 per pound. After assigning two contract deliveries to a third-party trader as a part of our cash management strategy to offset sales which were rescheduled to the end of the year by one of our customers, contract sales were as expected (462,000 pounds at an average price of $41.38 per pound); however, spot sales were lower than expected (100,000 pounds at an average price of $30.75) due to the continuing low spot price environment.

 

After more than three years of operations, the 2016 average plant head grade remained at 58 ppm despite having somewhat lower head grades for the fourth quarter. The lower head grade during this period of operation, as

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well as varying month-to-month grades, is a typical result as the mine matures and older operating patterns remain in the flow regime while newer patterns are brought online.

 

Updated Preliminary Economic Assessment for Lost Creek Property

 

In January 2016, we issued an updated Preliminary Economic Assessment for the Lost Creek Property Sweetwater County Wyoming (January 19, 2016 (TREC, Inc.)), which was then amended February 8, 2016 to include two additional tables to supplement the Cash Flow and OPEX tables as set forth in the prior document (as amended, the “Lost Creek PEA”). The Lost Creek PEA was prepared for the Company and its subsidiary, Lost Creek ISR, LLC, by Douglass H. Graves, P.E., TREC, Inc. (“TREC”) and James A. Bonner, C.P.G., Vice President Geology of the Company in accordance with NI 43-101.

 

According to the Lost Creek PEA, the mineral resources at the Lost Creek Property are as follows:

 

Lost Creek Property - Resource Summary

 

 

 

 

 

 

 

 

 

 

 

 

 

 

MEASURED

  

INDICATED

  

INFERRED

PROJECT

AVG GRADE

SHORT TONS

POUNDS

 

AVG GRADE

SHORT TONS

POUNDS

 

AVG GRADE

SHORT TONS

POUNDS

 

% eU3O8

(X 1000)

(X 1000)

 

% eU3O8

(X 1000)

(X 1000)

 

% eU3O8

(X 1000)

(X 1000)

LOST CREEK

0.048
8,339
7,937

 

0.046
3,831
3,491

 

0.046
3,116
2,844

MU1 production through 9/30/15

(0.048)
(1,415)
(1,358)

 

 

 

 

 

 

 

 

LC EAST

0.052
1,392
1,449

 

0.041
1,891
1,567

 

0.042
2,954
2,484

LC NORTH

-----

-----

-----

 

-----

-----

-----

 

0.045
645
581

LC SOUTH

-----

-----

-----

 

0.037

220

165

 

0.039
637
496

LC WEST

-----

-----

-----

 

-----

-----

-----

 

0.109
16
34

EN

-----

-----

-----

 

-----

-----

-----

 

-----

-----

-----

GRAND TOTAL

0.048
8,316
8,028

 

0.044
5,942
5,223

 

0.044
7,368
6,439

 

 

 

 

 

 

 

 

 

 

 

 

 

 

MEASURED + INDICATED =

14,258
13,251

 

 

 

 

 

Notes:

1.

Sum of Measured and Indicated tons and pounds may not add to the reported total due to rounding.

2.

% eU3O8 is a measure of gamma intensity from a decay product of uranium and is not a direct measurement of uranium. Numerous comparisons of eU3O8 and chemical assays of Lost Creek rock samples, as well as PFN logging, indicate that eU3O8 is a reasonable indicator of the chemical concentration of uranium.

3.

Table shows resources based on grade cutoff of 0.02 % eU3O8  and a grade x thickness cutoff of 0.20 GT.

4.

Measured, Indicated, and Inferred Mineral Resources as defined in Section 1.2 of NI 43-101 (the CIM Definition Standards (CIM Council, 2014)).

5.

Resources are reported through October 15, 2015.

6.

All reported resources occur below the static water table.

7.

1,358,407 lbs. of uranium have been produced from the HJ Horizon in MU1 (Lost Creek Project) as of September 30, 2015.

8.

Mineral resources that are not mineral reserves do not have demonstrated economic viability.

 

Information shown in the table above differs from the disclosure requirements of the SEC.  See Cautionary Note to U.S. Investors Concerning Disclosure of Mineral Resources, above.

 

The Lost Creek PEA discloses changes for the Lost Creek Property which come in the form of an updated mineral resource estimate prompted by recent drilling within Lost Creek’s MU2, exploratory drilling at the Lost Creek and LC East Projects, and the re-estimation of all previously-identified resources for the Property at a revised 0.20 grade-thickness (GT) cut-off. The economic analyses within the Lost Creek PEA have been revised

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to evaluate the impact of additional identified resources with information and data acquired through two years of ISR operations at Lost Creek. The Lost Creek PEA therefore serves to replace the last economic analyses for the Lost Creek Property from December 2013 and the most recent NI 43-101 Technical Report on the Lost Creek Property, dated June 17, 2015. The Lost Creek PEA covers production through September 30, 2015 and drilling and other exploration and operational activities conducted through October 15, 2015.

 

On June 17, 2015, the Company published an independent Technical Report for the Lost Creek Property to report increased resources for its operating MU1 and from exploration drilling conducted early in 2015. In order to reconcile higher-than-expected uranium recoveries from production operations in this mine unit, the grade thickness (“GT”) cutoff for uranium intercepts used in resource estimation was lowered from 0.30 to 0.20. Employing these revised guidelines, resources for MU1 were re-mapped and re-evaluated, increasing the MU1 Measured Resources by 55% (after subtraction of MU1 production). Through the monitoring of continued production from MU1, the authors believe the 0.20 GT better represents the uranium resources for the Lost Creek Property. Accordingly, for the Lost Creek PEA, all resource estimations for Lost Creek Property have used the new 0.20 GT cutoff, again, following re-mapping and re-evaluation. Since the June 17, 2015 Technical Report, our activities have resulted in a cumulative increase of mineral resources at the Lost Creek Property of 31% in the Measured and Indicated categories and 28% in the Inferred category.

 

The Lost Creek Property represents the composite of six individual contiguous Projects:  Lost Creek Project, LC East Project, LC West Project, LC North Project, LC South Project and EN Project. The fully-licensed and operating Lost Creek Project is considered the core project while the others are collectively referred to as the Adjoining Projects. The Adjoining Projects were acquired by the Company as exploration targets to provide resources supplemental to those recognized at the Lost Creek Project. Most were initially viewed as stand-alone projects, but expanded over time such that collectively they represent a contiguous block of land along with the Lost Creek Project.

 

The Lost Creek PEA mineral resource estimate includes drill data and analyses of approximately 3,200 historic and current holes and over 1.8 million feet of drilling at the Lost Creek Project alone. With the acquisition of the Lost Creek project, we acquired logs and analyses from 569 historic holes representing 366,268 feet of data. Since our acquisition of the project we have drilled 2,629 holes and wells including the construction and development drilling during 2013-2016 for MU1 and initial work in MU2 at Lost Creek. Drilling at Lost Creek through October 15, 2015 was included in the PEA. Additionally, drilling from the other five projects at the Lost Creek Property, both historic and our drill programs, is included in the mineral resource estimate. Collectively, this represents an additional 2,387 drill holes (1,306,331 feet). 

 

Regulatory Authorizations and Land Title of Lost Creek

 

Beginning in 2007, we completed all necessary applications and related processes to obtain the required permitting and licenses for the Lost Creek Project, of which the three most significant are: a Source and Byproduct Materials License from the NRC (received August 2011); a Plan of Operations with the BLM (Record of Decision (“ROD”) received October 2012; affirmed by U.S. District Court for the District of Wyoming, September 2013); and a Permit and License to Mine from the WDEQ (October 2011).  The WDEQ License to Mine was issued following determinations in favor of the project by the WEQC with respect to a third-party objection, which included a WEQC direction that the WDEQ Permit be approved by the WDEQ.  The WDEQ Permit includes the approval of the first mine unit, as well as the Wildlife Management Plan, including a positive determination of the protective measures at the project for the greater sage-grouse species.

Potential risks to the accessibility of the estimated mineral resource may include changes in the designation of the sage grouse as an endangered species by the USFWS because the Lost Creek Property lies within a sage grouse core area as defined by the state of Wyoming. In September 2015, the USFWS issued its finding that

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the greater sage grouse does not warrant protection under the Endangered Species Act (ESA). The USFWS reached this determination after evaluating the species’ population status, along with the collective efforts by the BLM and U.S. Forest Service, state agencies, private landowners and other partners to conserve its habitat.

 

After a thorough analysis of the best available scientific information and taking into account ongoing key conservation efforts and their projected benefits, the USFWS determined the species does not face the risk of extinction now or in the foreseeable future and therefore does not need protection under the ESA. Should future decisions vary, or state or federal agencies alter their management of the species, there could potentially be an impact on future expansion operations. However, the Company continues to work closely with the Wyoming Game and Fish Department (“WGFD”) and the BLM to mitigate impacts to the sage grouse.

 

The State of Wyoming has developed a “core-area strategy” to help protect the greater sage-grouse species within certain core areas of the state. Exploration areas of our Lost Creek property are all within a designated core area and are thus subject to work activity restrictions from March 1 to July 15 of each year.  The timing restriction precludes exploration drilling and other non-operational based activities which may disturb the sage-grouse. The sage-grouse timing restrictions relevant to ISR production and operational activities at the Lost Creek Project are somewhat different because the State has recognized that mining projects within core areas must be allowed to operate year-round. Therefore, there are no timing restrictions on drilling, construction, or operational activities within pre-approved disturbed areas within our permit to mine.

 

Meanwhile, in related regulatory processes, the BLM prepared and issued, in September 2015, environmental impact statements for and issued amendments to eleven Resource Management Plans (“RMPs”), related to the greater sage-grouse. Included in these RMPs are proposals to designate millions of acres of federal lands currently open for mineral location as lands to be withdrawn from such mineral status. At this time, there are no proposed withdrawals in the area of our mineral projects.

 

Additional authorizations from federal, state and local agencies for the Lost Creek project include: WDEQ-Air Quality Division Air Quality Permit and WDEQ-Water Quality Division Class I Underground Injection Control (“UIC”) Permit. The latter permit allows Lost Creek to operate up to five Class I injection wells to meet the anticipated disposal requirements for the life of the Lost Creek Project. The Environmental Protection Agency (“EPA”) issued an aquifer exemption for the Lost Creek project.  The WDEQ’s separate approval of the aquifer reclassification is a part of the WDEQ Permit. We also received approval from the EPA and the Wyoming State Engineer’s Office for the construction and operation of two holding ponds at Lost Creek.

 

In 2014, two applications for amendments to the primary authorizations to mine at Lost Creek were submitted to federal regulatory agencies, NRC and BLM, for the development and mining of LC East Project and the KM Horizon at Lost Creek. In 2015, the BLM issued a notice of intent to complete an environmental impact statement for the application. The NRC will participate in this review as a cooperating agency. A permit amendment requesting approval to mine at the LC East Project and within the KM Horizon at the Lost Creek Project was also submitted to the WDEQ for review and approval. Approval will include an aquifer exemption. The air quality permit will be revised to account for additional surface disturbance. An application will be submitted to Sweetwater County to re-zone the land at LC East. A subsequent Development Plan will also have to be submitted for review and approval. Numerous well permits from the State Engineer’s Office will be required.

 

During 2016, we received all authorizations for the operation of Underground Injection Control (UIC) Class V wells at Lost Creek. These approvals allow for the onsite recirculation of fresh permeate (i.e., clean water) into relatively shallow Class V wells. Site operators will use the reverse osmosis circuits, which were installed during initial construction of the plant, to treat process waste water into brine and permeate streams. The brine

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stream will continue to be disposed of in the UIC Class I deep wells while the clean, permeate stream will be injected into the UIC Class V wells. It is expected that these operational procedures will significantly enhance waste water capacity at the site.

 

Through certain of our subsidiaries, we control the federal unpatented lode mining claims and State of Wyoming mineral leases which make up the Lost Creek Property. Title to the mining claims is subject to rights of pedis possessio against all third-party claimants as long as the claims are maintained. The mining claims do not have an expiration date. Affidavits have been timely filed with the BLM and recorded with the Sweetwater County Recorder attesting to the payment of annual maintenance fees to the BLM as established by law from time to time.  The state leases have a ten-year term, subject to renewal for successive ten-year terms.

 

The surface of all the mining claims is controlled by the BLM, and we have the right to use as much of the surface as is necessary for exploration and mining of the claims, subject to compliance with all federal, state and local laws and regulations.  Surface use on BLM lands is administered under federal regulations.  Similarly, access to state-controlled land is largely inherent within the State of Wyoming mineral lease.  The state lease at the Lost Creek Project requires a nominal surface impact fee to be paid. The other state mineral leases currently do not have surface impact payment obligations. 

 

Exploration and Development Properties

 

Our Five Projects Adjoining Lost Creek Together with the Lost Creek Project Form the Lost Creek Property

 

The LC East and LC West Projects (currently, approximately 5,710 acres (2,310 hectares) and 3,840 acres (1,554 hectares), respectively) were added to the Lost Creek Property in 2012. The two projects were formed through location of new unpatented lode mining claims and an asset exchange completed in February 2012 with Uranium One Americas, Inc., through which we acquired 175 unpatented mining claims and related data. In 2012, all baseline studies at LC East were initiated. As discussed above, in 2014, we submitted applications for amendments of the Lost Creek licenses and permits to include development of LC East. We also located additional lode mining claims to secure the lands in what will be the LC East permit area. The East Mineral Trend (the “EMT”) is a second mineral trend of significance, in addition to the MMT at Lost Creek, identified by historic drilling on the lands forming LC East.  Although geologically similar, it appears to be a separate and independent trend from the MMT.  The Lost Creek PEA contains a recommendation that delineation drilling of identified resources in the EMT continue, together with progressing all necessary permit and license amendment to permit future production. 

 

The LC North Project (approximately 7,730 acres (3,120 hectares)) is located to the north and to the west of the Lost Creek Project. Historical wide-spaced exploration drilling on this project consisted of 175 drill holes.  The Company has conducted two drilling programs at the project. Exploration drilling at LC North is recommended by Company staff to pursue the potential of an extension of the MMT in the HJ and KM horizons.

 

The LC South Project (approximately 10,775 acres (4,360 hectares)) is located to the south and southeast of the Lost Creek Project. Historical drilling on the LC South Project consisted of 488 drill holes. In 2010, the Company drilled 159 exploration holes (total, 101,270 feet (30,867 meters)) which confirmed numerous individual roll front systems occurring within several stratigraphic horizons correlative to mineralized horizons in the Lost Creek Project.  Also, a series of wide-spaced drill holes were part of this exploration program which identified deep oxidation (alteration) that represents the potential for several additional roll front horizons. Staff also recommend that the HJ and KM horizons should be further explored, and suggest that additional drilling be conducted to further evaluate the potential of deeper mineralization.

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The EN Project (approximately 5,500 acres (~ 2,200 hectares)) is adjacent to and east of LC South. Ur-Energy has over 50 historical drill logs from the EN project. Some minimal, deep, exploration drilling has been conducted at the project. Although no mineral resource is yet reported due to the limited nature of the data, Company geologists continue to recommend that the EN project should be explored further with wide spaced framework drilling to assess regional alteration and stratigraphic relationships. During 2016, in an effort to contain costs, we reduced the number of federal mining claims and state mineral leases held at the EN project.

 

History and Geology of the Lost Creek Property

 

Uranium was discovered in the Great Divide Basin, where Lost Creek is located, in 1936.  Exploration activity increased in the early 1950s after the Gas Hills District discoveries, and continued to increase in the 1960s, with the discovery of numerous additional occurrences of uranium. Wolf Land and Exploration (which later became Inexco), Climax (Amax) and Conoco Minerals were the earliest operators in the Lost Creek area and made the initial discoveries of low-grade uranium mineralization in 1968. Kerr-McGee, Humble Oil, and Valley Development, Inc. were also active in the area.  Drilling within the current Lost Creek Project area from 1966 to 1976 consisted of approximately 115 wide-spaced exploration holes by several companies including Conoco, Climax (Amax), and Inexco.

 

Texasgulf acquired the western half of what is now the Lost Creek Project in 1976 through a joint venture with Climax and identified what is now referred to as the Main Mineral Trend (MMT).  In 1978, Texasgulf optioned into a 50% interest in the adjoining Conoco ground to the east and continued drilling, fully identifying the MMT eastward to the current Project boundary; Texasgulf drilled approximately 412 exploration holes within what is now the Lost Creek Project. During this period Minerals Exploration Company (a subsidiary of Union Oil Company of California) drilled approximately 8 exploration holes in what is currently the western portion of the Lost Creek Project.  Texasgulf dropped the project in 1983 due to declining market conditions. The ground was subsequently picked up by Cherokee Exploration, Inc. which conducted no field activities.

 

In 1987, Power Nuclear Corporation (also known as PNC Exploration) acquired 100% interest in the project from Cherokee Exploration, Inc. PNC Exploration conducted a limited exploration program and geologic investigation, as well as an evaluation of previous in situ leach testing by Texasgulf. PNC Exploration drilled a total of 36 holes within the current Project area.

 

In 2000, New Frontiers Uranium, LLC acquired the property and database from PNC Exploration, but conducted no drilling or geologic studies. New Frontiers Uranium, LLC later transferred the Lost Creek Project-area property along with its other Wyoming properties to its successor NFU Wyoming, LLC. In June 2005, Ur-Energy USA purchased 100% ownership of NFU Wyoming, LLC.

 

The Lost Creek Property is situated in the northeastern part of the GDB which is underlain by up to 25,000 ft. of Paleozoic to Quaternary sediments.  The GDB lies within a unique divergence of the Continental Divide and is bounded by structural uplifts or fault displaced Precambrian rocks, resulting in internal drainage and an independent hydrogeologic system. The surficial geology in the GDB is dominated by the Battle Spring Formation of Eocene age. The dominant lithology in the Battle Spring Formation is coarse arkosic sandstone, interbedded with intermittent mudstone, claystone and siltstone. Deposition occurred as alluvial-fluvial fan deposits within a south-southwest flowing paleodrainage. The sedimentary source is considered to be the Granite Mountains, approximately 30 miles to the north.  Maximum thickness of the Battle Spring Formation sediments within the GDB is 6,000 ft.

 

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Uranium deposits in the GDB are found principally in the Battle Spring Formation, which hosts the Lost Creek Project deposit. Lithology within the Lost Creek deposit consists of approximately 60% to 80% poorly consolidated, medium to coarse arkosic sands up to 50 ft. thick, and 20% to 40% interbedded mudstone, siltstone, claystone and fine sandstone, each generally less than 25 ft. thick. This lithological assemblage remains consistent throughout the entire vertical section of interest in the Battle Spring Formation.

 

Outcrop at Lost Creek is exclusively that of the Battle Spring Formation.  Due to the soft nature of the formation, the Battle Spring Formation occurs largely as sub-crop beneath the soil. The alluvial fan origin of the formation yields a complex stratigraphic regime which has been subdivided throughout Lost Creek into several thick horizons dominated by sands, with intervening named mudstones. Lost Creek is currently licensed and permitted to produce from the HJ horizon; we are currently seeking amendment of the licenses to be able to produce from the typically lower KM horizon.

The Company occasionally performs leach testing on various samples from the Lost Creek Project.  Most recently, in 2010, we performed leach testing on samples from the KM Horizon of the Lost Creek Project (currently in the permit-licensing stage). Seven samples obtained from one-foot sections of core were tested for mineral recovery using the same test methods as in prior tests from the HJ Horizon (currently licensed for production at Lost Creek, and being recovered in MU1). Twenty-five pore volumes of various bicarbonate leach solutions were passed through the samples. Uranium recovery ranged from 54.1 to 93.0% with an average uranium recovery of 80.6%. These results are similar to earlier leaching and recovery tests conducted on behalf of the Company on samples from the HJ Horizon, which returned results consistently averaging 82 – 83%. We believe these results are consistent with industry experience.

 

Pathfinder Mines Corporation:  Shirley Basin Mine Site (Shirley Basin, Wyoming) and Lucky Mc Mine Site (Gas Hills Mine District, Wyoming)

 

As a part of the Pathfinder acquisition, we now own the Shirley Basin and Lucky Mc mine sites in the Shirley Basin and Gas Hills mining districts of Wyoming, respectively, from which Pathfinder and its predecessors historically produced more than seventy-one million pounds of uranium, primarily from the 1960s through the 1990s. Pathfinder’s predecessors included COGEMA, Lucky Mc Uranium Corporation, and Utah Construction/Utah International.

 

Both Lucky Mc and Shirley Basin conventional mine operations were suspended in the 1990s due to low uranium pricing, and facility reclamation was substantially completed. We assumed the remaining reclamation responsibilities including financial surety for reclamation, at Shirley Basin and at the Lucky Mc mine site. The Lucky Mc tailings site was fully reclaimed and, at the time of our acquisition, was in the process of being transferred to the U.S. Department of Energy. Therefore, we assumed no obligations with respect to the Lucky Mc tailings site, which were retained by the seller upon closing, or the NRC license at the site.  We do not have plans for the further exploration or development of the Lucky Mc property during 2017.

 

Together with property holdings of patented lands, unpatented mining claims, and State of Wyoming and private leases totalling more than 5,500 acres (nearly 3,700 acres at Shirley Basin (approximately 1,500 hectares); approximately 1,800 at Lucky Mc (approximately 750 hectares)), we also acquired all historic geologic, engineering and operational data related to the two mine areas. Our project at Shirley Basin (the “Shirley Basin Project”) is located in Carbon County, Wyoming, approximately 40 miles south of Casper, Wyoming. The project is accessed by travelling west from Casper, on Highway 220. After travelling 18 miles, turn south on Highway 487 and travel an additional 35 miles; the entrance to Shirley Basin Mine is to the east.

 

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In addition to the two projects and related data, we acquired an extensive U.S. exploration and development database estimated to comprise hundreds of project descriptions in more than twenty states, including thousands of drill logs and geologic reports. Our geology team continues with its evaluation of this database, assessing opportunities for monetizing this additional asset. 

 

Under the terms of our acquisition of Pathfinder from AREVA in 2013, we were obligated to pay a five percent production royalty on production at the Shirley Basin Project under certain market conditions, if such conditions were triggered prior to June 30, 2016. That contingent royalty was capped to various triggers and could have been repurchased at our election. On June 30, 2016, the royalty lapsed and was terminated because the market conditions had not been triggered.

 

The tailings facility at the Shirley Basin site is one of the few remaining facilities in the United States that is licensed by the NRC to receive and dispose of byproduct waste material from other in situ uranium mines.  We assumed the operation of the byproduct disposal site and accepted deliveries throughout 2016 under several existing contracts.

 

Preliminary Economic Assessment for Shirley Basin Uranium Project

 

In 2014, we issued a Technical Report on Resources for the Shirley Basin Uranium Project Carbon County Wyoming (August 27, 2014). Subsequently, in January 2015, we issued a Preliminary Economic Assessment for the Shirley Basin Uranium Project Carbon County Wyoming, January 27, 2015 (the “Shirley Basin PEA”). The Shirley Basin PEA was prepared under the supervision of WWC Engineering.  The current mineral resources at the Shirley Basin Project are estimated as follows:

 

Shirley Basin Uranium Project - Resource Summary

 

 

 

 

 

 

 

 

 

MEASURED

INDICATED

RESOURCE

AVG GRADE

SHORT TONS

POUNDS

AVG GRADE

SHORT TONS

POUNDS

AREA

% eU3O8

(X 1000)

(X 1000)

(X 1000)

(X 1000)

(X 1000)

FAB
TREND

0.280
1,172

6,574 

0.119
456
1,081

AREA 5

0.243
195

947 

0.115
93
214

TOTAL

0.275
1,367

7,521 

0.118
549
1,295

 

 

 

MEASURED & INDICATED

0.230
1,915
8,816

 

Notes:

1.

Sum of Measured and Indicated tons and pounds may not add to the reported total due to rounding.

2.

Mineral resources that are not mineral reserves do not have demonstrated economic viability.

3.

Based on grade cutoff of 0.020 percent eU3O8 and a grade x thickness cutoff of 0.25 GT.

4.

Measured, Indicated, and Inferred Mineral Resources as defined in Section 1.2 of NI 43-101 (the CIM Definition Standards (CIM Council, 2014)).

5.

Resources are reported through July 2014.

6.

All reported resources occur below the historical, pre-mining static water table.

7.

Sandstone density is 16.0 cu. ft./ton.

 

Information shown in the table above differs from the disclosure requirements of the SEC. See Cautionary Note to U.S. Investors Concerning Disclosure of Mineral Resources, above.

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The Shirley Basin mineral resource estimate includes drill data and analyses of approximately three thousand two hundred holes and nearly 1.2 million feet of historic drilling at the Shirley Basin Project which were acquired with the acquisition of Pathfinder. We drilled 14 confirmation holes representing approximately 6,600 feet which were included in the mineral resource estimate.   

 

Shirley Basin History and Geology

 

The Shirley Basin property lies in the northern half of the historic Shirley Basin uranium mining district (the “District”), which is the second most prolific uranium mining district in Wyoming. Earliest discoveries were made in 1954 by Teton Exploration. This was followed by an extensive claim staking and drilling rush by several companies in 1957.  Several important discoveries were made and the first mining was started in 1959 by Utah Construction Corp. (predecessor to Pathfinder). Underground mining methods were initially employed but encountered severe groundwater removal problems, so in 1961 Utah Construction switched to solution mining methods. This was the first commercially successful application of in situ solution mining recovery (ISR) for uranium in the United States. In 1968 market and production needs caused Utah Construction to move to open-pit mining and a conventional mill.  All production within the district since that time has been by open-pit methods.

 

Several companies operated uranium mines within the District, however three companies were dominant. Utah Construction/Pathfinder’s efforts were focused in the northern portions of the District, while Getty was largely in the central portions, and Kerr-McGee was in the southern portions. In 1960, Getty and Kerr-McGee joined together as Petrotomics Company to build a mill for joint processing of their production. The last mining in the District ended in 1992 when Pathfinder shut down production due to market conditions. Total production from Shirley Basin was 51.3 million pounds of uranium, of which 28.3 million pounds came from the Utah Construction/Pathfinder operations which we now own.

 

Resources which we are currently targeting for ISR production represent unmined extensions of mineral trends addressed in past open-pit mines. These extensions had been targeted for mining but were abandoned with shut-down of the mining operations in 1992.

 

The Shirley Basin mining district lies in the north-central portions of the Shirley Basin geologic province, which is one of several inter-montane basins in Wyoming created 35-70 million years ago (mya) during the Laramide mountain building event. The Basin is floored by folded sedimentary formations of Cretaceous age (35-145 mya). These units were tilted by Laramide tectonic forces and subsequently exposed to erosion, creating a “paleo-topographic” surface. In the northern half of the Basin the Cretaceous units were later covered by stream sediments of the Wind River Formation of Eocene age (34-56 mya) which filled paleo-drainages cut into a paleo-topographic surface. The source of the Wind River sediments is granitic terrain within the nearby Laramie Range to the east and the Shirley Mountains to the southwest. The Wind River Formation was subsequently covered by younger volcanic ash-choked stream sediments of the White River and Arikaree Formations of Oligocene age (23-34 mya) and Miocene age (5-23 mya), respectively.

 

The Wind River Formation is the host of all uranium mineralization mined within the Shirley Basin mining district. The lithology of the Wind River Formation is characterized by multiple thick, medium to coarse grained sandstones separated by thick claystone shale units. The individual sandstones and shales are typically 20 to 50 feet thick. Total thickness of the Wind River Formation ranges from approximately 400 to 500 feet. The two most dominant sandstones are named the Main and Lower Sands. The Lower Sand represents the basal sand unit of the Wind River Formation and in places lies directly above the underlying Cretaceous formations.

 

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Uranium occurs as roll front type deposits along the edge of large regional alteration systems within sandstone units of the Wind River Formation. The source of the uranium is considered to be the volcanic ash content within the overlying White River Formation and also granitic content within the Wind River Formation itself.  The Main and Lower Sands are the primary hosts to mineralization which we are currently targeting for ISR development.  Studies we conducted in 2014, as well as previous studies by Pathfinder in the late 1990s, indicate that this mineralization is amenable to ISR extraction. The primary target is called the FAB Trend which represents the connecting mineral trend between two past-produced open-pits. A secondary target called Area 5 was also an ISR target for Pathfinder prior to shut-down of their mining operations in 1992.

 

The Bootheel Project, LLC and The Bootheel Project – Shirley Basin, Wyoming

 

Jet Metal Corp., formerly Crosshair Energy Corporation (“Jet Metal”) has been the manager of The Bootheel Project, LLC venture since 2007.  Following a decision to not fund our portion of the budget for the venture’s budget year ending March 31, 2012, our ownership interest was reduced from 25% to approximately 19%. Since then, we have maintained our ownership interest by participating in the project’s budgets and programs, which have been limited to nominal land maintenance (payment of maintenance for unpatented mining claims and of state lease rentals) and general overhead (e.g., insurance). In April 2016, the Management Committee of the Bootheel Project determined to continue the ownership and maintenance on the Bootheel property for the fiscal year ending March 31, 2017, which is the fiscal year end of The Bootheel Project, LLC.  No additional exploration or development activities are expected at this time for 2017. Due to the continuing decline in the spot price of uranium combined with the reduction in minerals when the related lease was not renegotiated, the Company examined the valuation of the investment and determined that as a standalone investment, it had an insignificant value and was therefore fully impaired during 2016 resulting in a loss on investment of $1.1 million. 

 

Competition and Mineral Prices

 

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. Because of their greater financial and technical resources, competitive bidding processes involving such companies will be challenging; this competition extends to the further acquisition of properties and also equipment, contractors and personnel required to explore and develop such properties. Additionally, these larger companies have greater resources to continue with their operations during periods of depressed market conditions.

 

Unlike other commodities, uranium does not trade on an open market.  Contracts are negotiated privately by buyers and sellers. Our existing long-term agreements are described in Item 1, Business and Properties, above and in Item 7, Management’s Discussion and Analysis, below.  Uranium prices are published by two of the leading industry-recognized independent market consultants, The Ux Consulting Company, LLC and TradeTech, LLC, who publish on their respective websites.  The following information reflects an average of the per pound prices published by these two consulting groups for the timeframe indicated:

 

 

 

 

 

 

 

 

 

December 31 of [year]

2011

2012

2013

2014

2015

2016

Spot price ($)

$
51.88
$
43.38
$
34.50
$
35.50
$
34.23
$
20.25

LT price ($)

$
62.00
$
56.50
$
50.00
$
49.50
$
44.00
$
30.00

 

 

 

 

 

 

 

 

 

 

End of [month]

31-Aug-16

30-Sep-16

31-Oct-16

30-Nov-16

31-Dec-16

31-Jan-17

28-Feb-17

Spot price (US$)

$
25.25
$
23.00
$
18.75
$
18.00
$
20.25
$
24.50
$
24.13

LT price (US$)

$
38.00
$
37.50
$
35.50
$
33.00
$
30.00
$
32.50
$
33.00

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The Long Term price as defined by Ux Consulting Company, LLC includes conditions for escalation (from current quarter) delivery timeframe (≥ 24 months), and quantity flexibility (up to ±10%) considerations.

 

Government Regulations

 

As set forth above, our exploration projects and operations at Lost Creek and our other projects in Wyoming 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 govern exploration, development, production, 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 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 and production.

 

Compliance with these laws and regulations may impose substantial costs on us and will subject us to significant potential liabilities. 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 adverse effect on our business operations.

 

Minerals exploration and development activities are subject to comprehensive regulation which may cause substantial delays or require capital outlays in excess of those anticipated, causing an adverse effect on our business operations. Minerals exploration operations are also subject to federal and state laws and regulations which 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. Minerals extraction 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. As of this date, other than with respect to the posting of a performance bond and the costs associated with our permitting and licensing activities, we have not been required to spend material amounts on compliance with environmental regulations. However, we may be required to do so in the future and this may affect our ability to expand or maintain our operations.

 

Environmental Regulations

 

As set forth above, our mineral projects are the subject of extensive environmental regulation at federal, state and local levels.

 

Exploration, development and production activities are subject to certain environmental regulations which may prevent or delay the commencement or continuance of our operations. In general, our exploration and production activities are subject to certain federal and state laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Compliance with these laws and regulations has not had a material effect on our operations or financial condition to date. Specifically, we are subject to legislation and regulations regarding radiation safety, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation requires well and facility sites to be abandoned and reclaimed to the satisfaction of state and federal authorities.

 

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Waste Disposal

 

The Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes, affect minerals exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes and on the disposal of non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (the "EPA"), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.

 

Underground Injection Control ("UIC") Permits

 

The federal Safe Drinking Water Act (“SDWA”) creates a nationwide regulatory program protecting groundwater. This act is administered by the EPA. However, to avoid the burden of dual federal and state regulation, the SDWA allows for the UIC permits issued by states to satisfy the UIC permit required under the SDWA under two conditions. First, the state's program must have been granted primacy, as is the case in Wyoming. Second, the EPA must have granted, upon request by the state, an aquifer exemption. The EPA may delay or decline to process the state's application if the EPA questions the state's jurisdiction over the mine site. The EPA commenced a rulemaking with its publication of 40 CFR Part 192 rules in early 2015. These proposed rules effectively seek to expand EPA jurisdiction in restoration of groundwater within an exempted aquifer, and propose to extend the time for monitoring such restoration and stabilization requirement for as much as thirty years following production. As proposed, the rules implicate RCRA, SDWA and Uranium Mill Tailings Radiation Control Act (UMTRCA) standards. The rulemaking is likely to take substantial time to complete and it is uncertain what the final rules will require. It is possible that additional requirements with attendant costs will result. 

 

CERCLA

 

The federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances ("Hazardous Substances"). These classes of persons or potentially responsible parties include the current and certain past owners and operators of a facility or property where there is or has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs of such action. We may also in the future become an owner of facilities on which Hazardous Substances have been released by previous owners or operators. We may in the future be responsible under CERCLA for all or part of the costs to clean up facilities or property at which such substances have been released, and for natural resource damages.

 

Most recently, the EPA has proposed a draft rulemaking to amend current standards of financial responsibility under Section 108(b) of CERCLA, which requires that classes of facilities establish and maintain evidence of financial responsibility consistent with the degree and duration of risk associated with the production, transportation, treatment, storage, or disposal of hazardous substances. As proposed, the rulemaking could significantly increase the cost of bonding and reclaiming our mineral projects.

 

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Air Emissions

 

Our operations are subject to 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.

 

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 and the State of Wyoming have promulgated regulations that require us to obtain permits to discharge storm water runoff. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.

 

Employees

 

At December 31, 2016, Ur-Energy USA employed 18 people in its Littleton, Colorado (8) and Casper, Wyoming (10) offices. Lost Creek ISR, LLC employed 41 people at the Lost Creek Project near Wamsutter, Wyoming.  None of our other subsidiaries had employees in 2016.

 

Corporate Offices

 

The registered office of Ur-Energy is located at 55 Metcalfe Street, Suite 1300, Ottawa, Ontario K1P 6L5.  Our United States corporate headquarters is located at 10758 West Centennial Road, Suite 200, Littleton, Colorado, 80127. We maintain a corporate and operations office at 5880 Enterprise Drive, Suite 200, Casper, Wyoming 82609. Lost Creek operational offices are located at 3424 Wamsutter / Crooks Gap Road, Wamsutter, Wyoming 82336.

 

Available Information

 

Detailed information about Ur-Energy is contained in our annual reports, quarterly reports, current reports on Form 8‑K, and other reports, and amendments to those reports that we file with or furnish to the SEC and the Canadian regulatory authorities. These reports are available free of charge on our website, www.ur-energy.com, as soon as reasonably practicable after we electronically file such reports with or furnish such reports to the SEC and the Canadian regulatory authorities.  However, our website and any contents thereof should not be considered to be incorporated by reference into this Annual Report on Form 10-K.

 

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We will furnish copies of such reports free of charge upon written request to our Corporate Secretary:

 

Ur-Energy Inc.

Attention: Corporate Secretary

10758 West Centennial Road, Suite 200

Littleton, Colorado 80127

Telephone: 1-866-981-4588

Email: legaldept@ur-energy.com

 

Additionally, our corporate governance guidelines, Code of Ethics and the charters of each of the standing committees of our Board of Directors are available on our website. We will furnish copies of such information free of charge upon written request to our Corporate Secretary, as set forth as above.

 

Other information relating to Ur-Energy may be found on the SEC’s website at http://www.sec.gov/edgar.shtml or on the SEDAR website at www.sedar.com.  Our reports can be read and copied by the public at the SEC’s Public Reference Room at 100 F Street, NE., Washington, D.C. 20549.

 

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Item 1A.  RISK FACTORS

 

An investment in our securities involves a high degree of risk. You should consider the following discussion of risks in addition to the other information in this annual report before purchasing any of our securities. In addition to historical information, the information in this annual report contains “forward-looking” statements about our future business and performance. Our actual operating results and financial performance may be very different from what we expect as of the date of this annual report. The risks below address material factors that may affect our future operating results and financial performance.

 

Risks Related to Our Business

 

The uranium market is volatile and has limited customers. Current inventories and largely unrestricted imports challenge the US domestic industry.

 

The marketability of uranium and acceptance of uranium mining is subject to numerous factors beyond our control. The price of uranium may experience volatile and significant price movements over short periods of time. Factors affecting the market include demand for nuclear power; changes in public acceptance of nuclear power generation as a result of any future accidents or terrorism at nuclear facilities, including the continuing effects on the market due to the events following the earthquake and tsunami in Japan in March 2011; political and economic conditions in uranium mining, producing and consuming countries; costs and availability of financing of nuclear plants; reprocessing of spent fuel and the re-enrichment of depleted uranium tails or waste. Moreover, increasing inventories, sales of excess civilian and military inventories (including from the dismantling of nuclear weapons) by governments and industry participants, as well as the production levels and costs of production in countries such as Kazakhstan have had a substantial impact on the domestic industry.  If the higher inventories and the imports from Kazakhstan and other low-cost production sites remain unchecked on a continuing basis, there could be a significant negative impact to the uranium market which could adversely impact the Company’s future profitability.

 

Our property interests and our projects are subject to volatility in the price of uranium.

 

The price of uranium is volatile. Changes in the price of uranium depend on numerous factors beyond our control including international, economic and political trends; changes in public acceptance of nuclear power generation as a result of any future accidents or terrorism at nuclear facilities, including the longer-term effects on the market due to the events following the earthquake and tsunami affecting the Fukushima Daiichi nuclear power station in Japan in 2011; changes in governmental regulations; expectations of inflation; currency exchange fluctuations; interest rates; global or regional consumption patterns; speculative activities and increased production due to new extraction developments and improved extraction and production methods. The effect of these factors on the price of uranium, and therefore on the economic viability of our properties cannot accurately be predicted.  Because most of our properties are in exploration and development stage and Lost Creek commenced operations just over three years ago, it is not yet possible for us to control the impact of fluctuations in the price of uranium.

 

Mining operations involve a high degree of risk.

 

Mining operations generally involve a high degree of risk. We continue operations at our first and, currently, only, uranium in situ recovery facility at Lost Creek, where production activities commenced in the second half of 2013. Our operations at the Lost Creek site, which is a remote site in south-central Wyoming, and at other projects as they continue in development will be subject to all the hazards and risks normally encountered in the production of uranium by in situ methods of recovery, including unusual and unexpected geological

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formations, unanticipated metallurgical difficulties, water management including waste water disposal capacity, equipment malfunctions and parts unavailability, interruptions of electrical power and communications, other conditions involved in the drilling and removal of material through pressurized injection and production wells, radiation safety, transportation and industrial accidents, any of which could result in damage to, or destruction of, mines and other producing facilities, damage to life or property, environmental damage and possible legal liability. Adverse effects on operations and/or further development of our projects could also adversely affect our business, financial condition, results of operations and cash flow.

 

Our business is subject to extensive environmental and other regulations that may make exploring, mining or related activities expensive, and which may change at any time.

 

The mining industry is subject to extensive environmental and other laws and regulations, which may change at any time. Environmental legislation and regulation is evolving in a manner which will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their officers, directors and employees. In addition to the ESA decision made in 2015, to not list the greater sage-grouse as an endangered species, other rulemakings and proposed legislation are ongoing.  For example, the EPA continues with its rulemaking on changes to Part 192, which sets forth groundwater restoration and stabilization requirements for ISR uranium projects. Other EPA rulemakings relating to maintenance of tailings facilities and holding ponds, which may also have an impact on ISR projects, including Lost Creek are at various stages (e.g., UMTRCA, RCRA and SDWA restoration and stabilization requirements). The changes currently proposed to CERCLA regulations, which would significantly increase financial obligations and surety bonding, could also have a commensurate impact on ISR projects. These are not the only laws and regulations which are the subject of discussion and proposed more restrictive changes. Moreover, compliance with environmental quality requirements and reclamation laws imposed by federal, state and local governmental authorities may require significant capital outlays, materially affect the economics of a given property, cause material changes or delays in intended activities, and potentially expose us to litigation and other legal or administrative proceedings. We cannot accurately predict or estimate the impact of any such future laws or regulations, or future interpretations of existing laws and regulations, on our operations. Historic exploration activities have occurred on many of our properties and mining and energy production activities have occurred near certain of our properties. If such historic activities have resulted in releases or threatened releases of regulated substances to the environment, or historic activities require remediation, potential for liability may exist under federal or state remediation statutes.

 

The uranium mining industry is capital intensive, and we may be unable to raise necessary additional funding.

 

Additional funds likely may be required to fund working capital or to fund exploration and development activities at our properties including Lost Creek and the adjoining projects at the Lost Creek Property, as well as the development of our Shirley Basin project. Potential sources of future funds available to us, in addition to the sales proceeds from Lost Creek production, include the sale of additional equity capital, proceeds from the exercise of outstanding convertible equity instruments, borrowing of funds or other debt structure, project financing, or the sale of our interests in assets. There is no assurance that such funding will be available to us to continue development or future exploration. Furthermore, even if such financing is successfully completed, there can be no assurance that it will be obtained on terms favorable to us or will provide us with sufficient funds to meet our objectives, which may adversely affect our business and financial position. In addition, any future equity financings may result in substantial dilution for our existing shareholders.

 

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Our mineral resource estimates may not be reliable; there is risk and increased uncertainty to commencing and conducting production without established mineral reserves; and we need to develop additional resources to sustain ongoing operations.

 

Our properties do not contain any mineral reserves as defined under SEC Industry Guide 7. See “Cautionary Note to United States Investors Concerning Disclosure of Mineral Resources” above. Until mineral reserves or mineral resources are actually mined and processed, the quantity of mineral resources and grades must be considered as estimates only. The Company has established the existence of uranium resources for certain uranium projects, including the Lost Creek Property. The Company has not established proven or probable reserves, as defined by Canadian securities regulators or the SEC under Industry Guide 7, through the completion of a final or “bankable” feasibility study for any of its uranium projects, including the Lost Creek Property. Furthermore, the Company has no plans to establish proven or probable reserves for any of its uranium projects for which the Company plans on utilizing ISR mining, such as the Lost Creek Project or the Shirley Basin Project. As a result, and despite the fact that the Company commenced recovery of U3O8 at the Lost Creek Project in August 2013, there is an increased uncertainty and risk that may result in economic and technical failure which may adversely impact the Company’s future profitability.

 

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 estimated mineral reserves or mineral resources will be realized. In general, estimates of mineral resources are based upon a number of factors and assumptions made as of the date on which the estimates were determined, including:

 

·

geological and engineering estimates that have inherent uncertainties and the assumed effects of regulation by governmental agencies;

·

the judgment of the geologists, engineers and other professionals preparing the estimate;

·

estimates of future uranium prices and operating costs;

·

the quality and quantity of available data;

·

the interpretation of that data; and

·

the accuracy of various mandated economic assumptions, all of which may vary considerably from actual results.

 

All estimates are, to some degree, uncertain. 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.

 

As well, because we are now in operation and are depleting our known resource at Lost Creek, we must continue to conduct exploration and develop additional mineral resources. While there remain large areas of our Lost Creek Property which require additional exploration, and we have identified mineral resources at our Shirley Basin Project, we will need to continue to explore other areas of the Lost Creek Property and our other mineral properties in Wyoming, or acquire additional, known mineral resource properties to replenish our mineral resources and sustain continued operations. We estimate life of mine when we prepare our mineral resource estimates, but such estimates may not be correct.

 

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Restrictive covenants in agreements governing our indebtedness may restrict our ability to pursue our business strategies. If we are unable to service our indebtedness, we could lose the assets securing our indebtedness.

 

Our State Bond Loan, under which we originally received approximately $34 million in debt financing, includes restrictive covenants that, among other things, limit our ability to sell the assets securing our indebtedness (which include our Lost Creek Project and other related assets). Our ability to make scheduled payments and satisfy other covenants in the State Bond Loan depends on our financial condition and operating performance, which are subject to prevailing economic, competitive, legislative and regulatory conditions beyond our control. We may be unable to generate a level of cash flow from operating activities sufficient to permit us to pay the principal, interest and other fees on our indebtedness.

 

If we cannot make scheduled payments on our debt, we will be in default which, if not addressed or waived, could require accelerated repayment of our indebtedness and the enforcement by the lender against the assets securing our indebtedness. The secured collateral for the State Bond Loan includes the Lost Creek Project and other related assets. These are key assets on which our business is substantially dependent and as such, the enforcement against any one or all of these assets would have a material adverse effect on our operations and financial condition.

 

Our mining operations are subject to numerous environmental laws, regulations and permitting requirements and bonding requirements that can delay production and adversely affect operating and development costs.

 

Our business is subject to extensive federal, state, provincial and local laws governing prospecting and development, taxes, labor standards and occupational health, mine and radiation safety, toxic substances, environmental protection, endangered species protections, and other matters. Exploration, development and production operations are also subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws impose high standards on the mining industry, and particularly standards with respect to uranium recovery, to monitor the discharge of waste water and report the results of such monitoring to regulatory authorities, to reduce or eliminate certain effects on or into land, water or air, to progressively restore mine properties, to manage hazardous wastes and materials and to reduce the risk of worker accidents. A violation of these laws may result in the imposition of substantial fines and other penalties and potentially expose us to operational restrictions, suspension, administrative proceedings or litigation.  Many of these laws and regulations have tended to become more stringent over time. Any change in such laws could have a material adverse effect on our financial condition, cash flow or results of operations.  There can be no assurance that we will be able to meet all the regulatory requirements in a timely manner or without significant expense or that the regulatory requirements will not change to delay or prohibit us from proceeding with certain exploration, development or operations. Further, there is no assurance that we will not face new challenges by third parties to regulatory decisions when made, which may cause additional delay and substantial expense, or may cause a project to be permanently halted.

 

Many of our operations require licenses and permits from various governmental authorities. We believe we hold all necessary licenses and permits to carry on the activities which we are currently conducting or propose to conduct under applicable laws and regulations. Such licenses and permits are subject to changes in regulations and changes in various operating circumstances. There can be no guarantee that we will be able to obtain all necessary licenses and permits that may be required to maintain our exploration and mining activities including constructing mines or milling facilities and commencing or continuing exploration or mining activities or operations at any of our properties. In addition, if we proceed to production on any other exploration property, we must obtain and comply with permits and licenses which will contain specific operating conditions. There

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can be no assurance that we will be able to obtain such permits and licenses or that we will be able to comply with any such conditions.

 

Lack of acceptance of nuclear energy and deregulation of the electrical utility industry could impede our business.

 

Our future prospects are tied directly to the electrical utility industry worldwide. Deregulation of the utility industry, particularly in the United States and Europe, is expected to affect the market for nuclear and other fuels for years to come, and may result in a wide range of outcomes including the expansion or the premature shutdown of nuclear reactors. Maintaining the demand for uranium at current levels and future growth in demand will depend upon the continued acceptance of the nuclear technology as a means of generating electricity.  Lack of continued public acceptance of nuclear technology would adversely affect the demand for nuclear power and potentially increase the regulation of the nuclear power industry.  Following the events of March 2011 in Fukushima Japan, a reaction worldwide called into question the public’s confidence in nuclear energy and technology, the effects of which are still apparent in many countries around the world.

 

We have entered into term sales contracts for a portion of our production, and there can be no guarantee that we will be able to enter into new term sales contracts in the future on suitable terms and conditions.

 

Those contracts, which have historically resulted in uranium sales at prices in excess of spot prices, have fixed delivery terms. Certain of our contracts have delivery terms that have expired with no future deliveries planned. The failure to enter into new term sales contracts on suitable terms, could adversely impact our operations and mining activity decisions, and resulting cash flows and income.

 

The results of exploration and ultimate production are highly uncertain.

 

The exploration for, and development of, mineral deposits involves significant risks which a combination of careful evaluation, experience and knowledge may not eliminate. Few properties which are explored are ultimately developed into producing mines. Major expenses may be required to establish mineral resources or reserves, to develop metallurgical processes and to construct mining and processing facilities at a particular site. It is impossible to ensure that our current exploration and development programs will result in profitable commercial operations.

 

Whether a mineral deposit will be commercially viable depends on a number of factors, some of which are the particular attributes of the deposit, such as size, grade and proximity to infrastructure, as well as uranium prices, which are highly cyclical, and government regulations, including regulations relating to prices, taxes, royalties, land tenure, land use, importing and exporting of uranium and environmental protection. The exact effect of these factors cannot be accurately predicted, but the combination of these factors may result in us not receiving an adequate return on invested capital.

 

The uranium industry is highly competitive and is competitive with other energy sources.

 

The international uranium industry is highly competitive. Our activities are directed toward the search for, evaluation, acquisition and development of uranium deposits into production operations. There is no certainty that the expenditures to be made by us will result in discoveries of commercial quantities of uranium deposits. There is aggressive competition within the mining industry for the discovery and acquisition of properties considered to have commercial potential. We will compete with other interests, many of which have greater financial resources than we have, for the opportunity to participate in promising projects. Significant capital investment is required to achieve commercial production from successful exploration and development efforts.

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Nuclear energy competes with other sources of energy, including oil, natural gas, coal, hydro-electricity and renewable energy sources. These other energy sources are to some extent interchangeable with nuclear energy, particularly over the longer term. Lower prices of oil, natural gas, coal and hydro-electricity may result in lower demand for uranium concentrate and uranium conversion services. Furthermore, the growth of the uranium and nuclear power industry beyond its current level 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.

 

Our property title may be uncertain and could be challenged.

 

Although we have obtained title opinions with respect to certain of our properties, there is no guarantee that title to any of our properties will not be challenged or impugned.  Third parties may have valid claims underlying portions of our interests.  Our mineral properties in the United States consist of leases to private mineral rights, leases covering state lands, unpatented mining claims and patented mining claims. Many of our mining properties in the United States are unpatented mining claims to which we have only possessory title. Because title to unpatented mining claims is subject to inherent uncertainties, it is difficult to determine conclusively ownership of such claims. These uncertainties relate to such things as sufficiency of mineral discovery, proper posting and marking of boundaries and possible conflicts with other claims not determinable from descriptions of record. The present status of our unpatented mining claims located on public lands allows us the exclusive right to mine and remove valuable minerals. We are allowed to use the surface of the public lands solely for purposes related to mining and processing the mineral-bearing ores. However, legal ownership of the land remains with the United States. We remain at risk that the mining claims may be forfeited either to the United States or to rival private claimants due to failure to comply with statutory requirements. We have taken or will take appropriate curative measures to ensure proper title to our properties where necessary and where possible.

 

Possible amendments to the General Mining Law could make it more difficult or impossible for us to execute our business plan.

 

Members of the United States Congress have repeatedly introduced bills which would supplant or alter the provisions of the United States Mining Law of 1872, as amended. 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 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 laws, and (vii) allow for administrative determinations that mining would not be allowed in situations where undue degradation of the federal lands in question could not be prevented.

 

If enacted, such legislation could, among other effects, 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 development and the economics of existing operating mines. Passage of such legislation could adversely affect our financial performance.

 

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Additionally, as noted in other risk factors, there are ongoing withdrawals of federal lands for the purposes of mineral location and development. While such proposals are not yet final and, as yet, do not directly affect the area of Wyoming in which we currently have land holdings, they could have an adverse effect on our financial performance if they are broadened in scope to directly affect the areas in which we have properties.

 

We do not have an established earnings record, and we have never paid dividends.

 

We do not have an established earnings record. We have not paid dividends on our Common Shares since incorporation and do not anticipate doing so in the foreseeable future. Payments of any dividends will be at the discretion of our Board after taking into account many factors, including our financial condition and current and anticipated cash needs.

 

We depend on the services of our management, key personnel, contractors and service providers.

 

Shareholders will be relying on the good faith, experience and judgment of our management and advisors in supervising and providing for the effective management of the business and our operations and in selecting and developing new investment and expansion opportunities. We may need to recruit additional qualified employees, contractors and service providers to supplement existing management and personnel, the timely availability of which cannot be assured, particularly in the current labor markets in which we recruit our employees and the somewhat remote locations for which employees are needed. As well, the skilled professionals with expertise in engineering and process aspects of in situ recovery, radiation safety and other facets of our business are currently in high demand, as there are relatively few such professionals with both expertise and experience. We will need to hire additional employees as we develop the Shirley Basin Project. We will continue to be dependent on a relatively small number of key persons, including key contractors, the loss of any one or several of whom could have an adverse effect on our business and operations. We do not hold key man insurance in respect of any of our executive officers.

 

Our insurance coverage could be insufficient.

 

We currently carry insurance coverage for general liability, directors’ and officers’ liability and other matters.  We intend to carry insurance to protect against certain risks in such amounts as we consider adequate. Certain insurances may be cost prohibitive to maintain, and even if we carried all such insurances, the nature of the risks we face in our exploration and uranium production operations is such that liabilities could exceed policy limits in any insurance policy or could be excluded from coverage under an insurance policy. The potential costs that could be associated with any liabilities not covered by insurance or in excess of insurance coverage or compliance with applicable laws and regulations may cause substantial delays and require significant capital outlays, adversely affecting our business and financial position. Additionally, we utilize a bonding surety program for our regulatory, reclamation and restoration obligations at Lost Creek Project and the Pathfinder Mines sites. Availability of and terms for such surety arrangements may change in the future, resulting in adverse effects to our financial condition.

 

We are subject to risks associated with regulatory investigations or challenges, litigation and other legal proceedings.

 

Defense and settlement costs of legal claims can be substantial, even with respect to claims that have no merit. From time to time, we may be involved in disputes with other parties which may result in litigation or other proceedings. Additionally, it is not unlikely that we may find ourselves involved directly or indirectly in legal proceedings, in the form of regulatory investigations, administrative proceedings or litigation, arising from challenges to regulatory actions as described elsewhere in this annual report. Such investigations, administrative

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proceedings and litigation related to regulatory matters may delay or halt exploration or development of our projects. The results of litigation or any other proceedings cannot be predicted with certainty. If we are unable to resolve any such disputes favorably, it could have a material adverse effect on our financial position, ability to operate, results of operations or our property development.

 

Acquisitions and integration may disrupt our business.

 

From time to time, we examine opportunities to acquire additional mining assets and businesses. Any acquisition that we may choose to complete may be of significant size, may change the scale of our business and operations, and/or may expose us to new geographic, political, operating, financial and geological risks. Any acquisitions would be accompanied by risks. For example, there may be a significant change in commodity prices after we have committed to complete the transaction and established the purchase price or share exchange ratio; a material ore body may prove to be below expectations; we may have difficulty integrating and assimilating the operations and personnel of any acquired company, realizing anticipated synergies and maximizing the financial and strategic position of the combined enterprise, and maintaining uniform standards, policies and controls across the organization; the integration of the acquired business or assets may disrupt our ongoing business and relationships with employees, customers, suppliers and contractors; and the acquired business or assets may have unknown liabilities which may be significant. There can be no assurance that we would be successful in overcoming these risks or any other problems encountered in connection with such acquisitions.

 

We are dependent on information technology systems, which are subject to certain risks.

 

We depend upon information technology systems in a variety of ways throughout our operations.  Any significant breakdown of those systems, whether through virus, cyber-attack, security breach, theft, or other destruction, invasion or interruption, or unauthorized access to our systems, could negatively impact our business and operations. To the extent that such invasion, cyber-attack or similar security breach results in disruption to our operations, loss or disclosure of, or damage to, our data and particularly our confidential or proprietary information, our reputation, business, results of operations and financial condition could be materially adversely affected.  Our systems, internal controls and insurance for protecting against such cyber security risks may be insufficient.  Although to date we have experienced no such attack resulting in material losses, we may suffer such losses at any time in the future.  We may be required to expend significant additional resources to continue to modify and enhance our protective measures or to investigate, restore or remediate any information technology security vulnerabilities.

 

U.S. Federal Income Tax Consequences to U.S. Shareholders under the Passive Foreign Investment Company Rules

 

Investors in the Common Shares of Ur-Energy that are U.S. taxpayers (referred to as a U.S. shareholder) should be aware that we may be a “passive foreign investment company” (a “PFIC”) for the period ended December 31, 2016 and may be a PFIC in subsequent years. If we are a PFIC for any year during a U.S. shareholder’s holding period, then such U.S. shareholders generally will be subject to a special, highly adverse tax regime with respect to so-called “excess distributions” received on our Common Shares.  Gain realized upon a disposition of our Common Shares (including upon certain dispositions that would otherwise be tax-free) also will be treated as an excess distribution. Excess distributions are punitively taxed and are subject to additional interest charges.  Additional special adverse rules also apply to U.S. shareholders who own Common Shares of Ur-Energy if we are a PFIC and have a non-U.S. subsidiary that is also a PFIC (a “lower-tier PFIC”).

 

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A U.S. shareholder may make a timely "qualified electing fund" election (“QEF election”) or a "mark-to-market" election with respect to our Common Shares to mitigate the adverse tax rules that apply to PFICs, but these elections may accelerate the recognition of taxable income and may result in the recognition of ordinary income. To be timely, a QEF election generally must be made for the first year in the U.S. shareholder’s holding period in which Ur-Energy is a PFIC.  A U.S. shareholder may make a QEF election only if the U.S. shareholder receives certain information (known as a “PFIC annual information statement”) from us annually. A U.S. shareholder may make a QEF election with respect to a lower-tier PFIC only if it receives a PFIC annual information statement with respect to the lower tier PFIC.  The mark-to-market election is available only if our Common Shares are considered regularly traded on a qualifying exchange, which we cannot assure will be the case for years in which it may be a PFIC.  The mark-to-market election is not available for a lower-tier PFIC.

 

We will use commercially reasonable efforts to make available to U.S. Holders, upon their written request:  (a) timely and accurate information as to our status as a PFIC and the PFIC status of any subsidiary in which Ur-Energy owns more than 50% of such subsidiary’s total aggregate voting power, and (b) for each year in which Ur-Energy determines that it is a PFIC, upon written request, a PFIC annual information statement with respect to Ur-Energy and with respect to each such subsidiary that we determine is a PFIC.

 

Special adverse rules that impact certain estate planning goals could apply to our Common Shares if we are a PFIC. Each U.S. shareholder should consult its own tax advisor regarding the U.S. federal, state and local consequences of the PFIC rules, and regarding the QEF and mark-to-market elections.

 

Item 1B.  UNRESOLVED STAFF COMMENTS

 

None.

 

Item 3.  LEGAL PROCEEDINGS

 

None.

 

Item 4.  MINE SAFETY DISCLOSURE

 

Our operations and other activities at Lost Creek are not subject to regulation by the Federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”).

 

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PART II

 

Item 5.  MARKET FOR registrant’s COMMON EQUITY, RELATED STOCKHOLDER MATTERS and issuer purcHases of equity securities

 

Market Information

 

Since July 24, 2008, Ur-Energy’s Common Shares have been listed for trading on the NYSE MKT exchange under the trading symbol “URG.” The following table sets forth the price range per share and trading volume for the Common Shares:

 

 

 

 

 

 

 

NYSE

 

Common Shares

 

Volume

High

Low

Quarter Ending

 

US$

31-Mar-15

18,238,072
1.07
0.75

30-Jun-15

22,003,580
1.07
0.76

30-Sep-15

17,091,632
0.82
0.53

31-Dec-15

17,343,488
0.68
0.45

 

 

 

 

31-Mar-16

19,405,444
0.70
0.44

30-Jun-16

28,373,457
0.73
0.45

30-Sep-16

15,562,319
0.64
0.47

31-Dec-16

23,271,636
0.59
0.41

 

 

 

 

January 1, 2017 to March 2, 2017

41,575,111
0.91
0.52

 

Since November 29, 2005, Ur-Energy’s Common Shares have been listed and posted for trading on the Toronto Stock Exchange under the trading symbol “URE.” The following table sets forth the price range per share and trading volume for the Common Shares:

 

 

 

 

 

 

 

TSX

 

Common Shares

 

Volume

High

Low

Quarter Ending

 

CDN$

31-Mar-15

4,470,129
1.35
0.94

30-Jun-15

3,517,095
1.31
0.96

30-Sep-15

2,765,418
1.02
0.72

31-Dec-15

2,621,959
0.90
0.60

 

 

 

 

31-Mar-16

4,531,828
0.98
0.61

30-Jun-16

4,164,964
0.92
0.60

30-Sep-16

2,301,377
0.82
0.63

31-Dec-16

4,330,226
0.78
0.55

 

 

 

 

January 1, 2017 to March 2, 2017

8,865,561
1.19
0.70

 

 

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Holders

 

The authorized capital of Ur-Energy consists of an unlimited number of Common Shares and an unlimited number of Class A Preference Shares. As of March 2, 2017, 145,616,297 Common Shares are issued and outstanding and no preferred shares are issued and outstanding.  We estimate that we have approximately 18,000 beneficial holders of our Common Shares. The holders of the Common Shares are entitled to one vote per share at all meetings of our shareholders. The holders of Common Shares are also entitled to dividends, if and when declared by our Board and the distribution of the residual assets of the company in the event of a liquidation, dissolution or winding up.

 

Our Class A Preference Shares are issuable by the directors in one or more series and the directors have the right and obligation to fix the number of shares in, and determine the designation, rights, privileges, restrictions and conditions attaching to the shares of each series. The rights of the holders of Common Shares will be subject to, and may be adversely affected by, the rights of the holders of any Class A Preference Shares that may be issued in the future. The Class A Preference Shares, may, at the discretion of the Board, be entitled to a preference over the Common Shares and any other shares ranking junior to the Class A Preference Shares with respect to the payment of dividends and distribution of assets in the event of liquidation, dissolution or winding up.

 

Shareholder Rights Plan

 

Ur-Energy maintains a shareholder rights plan (the “Rights Plan”) designed to encourage the fair and equal treatment of shareholders in connection with any take-over bid for the Company's outstanding securities.  The Rights Plan is intended to provide the Board with adequate time to assess a take-over bid, to consider alternatives to a take-over bid as a means of maximizing shareholder value, to allow competing bids to emerge, and to provide our shareholders with adequate time to properly assess a take-over bid without undue pressure. The Rights Plan was reconfirmed by shareholders at Ur-Energy’s annual and special meeting of shareholders on May 28, 2015.

 

Dividends

 

To date, we have not paid any dividends on our outstanding Common Shares and have no current intention to declare dividends on the Common Shares in the foreseeable future. Any decision to pay dividends on our Common Shares in the future will be dependent upon our financial requirements to finance future growth, the general financial condition of the Company and other factors which our Board may consider appropriate in the circumstances.

 

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Securities Authorized for Issuance under Equity Compensation Plans

 

The following table sets forth certain summary information concerning our equity compensation plans as at December 31, 2016.  Directors, officers, employees, and consultants are eligible to participate in the Option Plan.  Directors and employees, including executive officers, are eligible to participate in the RSU Plan.

 

 

 

 

 

 

Number of Common Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (4)

Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (2)

(C$)

Number of Common Shares Remaining for Future Issuance (Excluding Common Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights) (3)

Equity compensation plans approved by securityholders (1)

11,031,658

$ 0.78

1,571,234

Equity compensation plans not approved by security-holders

 -

 -

 -

 

(1)

Our shareholders have approved both the Ur-Energy Inc. Amended and Restated Stock Option Plan 2005, as amended, and the Ur-Energy Inc. Amended Restricted Share Unit Plan.

(2)

The exercise price represents the weighted exercise price of the 9,748,934 outstanding stock options under the Ur‑Energy Inc. Amended and Restated Stock Option Plan 2005.

(3)

Represents 630,234 Common Shares remaining available for issuance under the Ur-Energy Inc. Amended and Restated Stock Option Plan 2005 and 941,000 Common Shares available under the Ur-Energy Amended Restricted Share Unit Plan.

(4)

The warrants included represent only those which form a portion of compensation for certain consultants and our commercial lender.

 

Recent Sales of Unregistered Securities

 

On August 19, 2014, we filed a universal shelf registration statement on Form S-3 in order that we may offer and sell, from time to time, in one or more offerings, at prices and terms to be determined, up to $100 million of our Common Shares, warrants to purchase our Common Shares, our senior and subordinated debt securities, and rights to purchase our Common Shares and/or our senior and subordinated debt securities.  The registration statement became effective September 12, 2014. The 12,921,000 Common Shares offered in the February 2016 financing were sold for $0.50 per share raising $5.7 million (net of issue costs of $0.8 million) under the shelf registration statement. 

 

On May 27, 2016, we entered into an At Market Issuance Sales Agreement with MLV & Co. LLC and FBR Capital Markets & Co. under which we may, from time to time, issue and sell Common Shares at market prices on the NYSE MKT or other U.S. market through the distribution agents for aggregate sales proceeds of up to $10,000,000. During 2016, we sold 164,979 Common Shares under the sales agreement at an average price of $0.65 per share for gross proceeds of $108 thousand. After deducting transaction fees and commissions we received net proceeds of $105 thousand. After deducting all other costs associated with the completion of the agreement and filing the related prospectus supplement, we received $13 thousand.

 

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During the fiscal years ended December 31, 2016 and 2015, we did not have any sales of securities in transactions that were not registered under the Securities Act.

Issuer Purchases of Equity Securities

 

The Company did not purchase its own equity securities during the fiscal year ended December 31, 2016.

 

Performance Graph

 

The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to the liabilities of Section 8 of the Exchange Act, and will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such a filing.

 

The following graph illustrates the period from December 31, 2011 to December 31, 2016 and reflects the cumulative shareholder return of an investment in our Common Shares compared to the cumulative return of an investment in (a) the Russell 3000 Index, (b) the NYSE MKT Composite Index, and (c) the average of a peer group consisting of Denison Mines Corp., Uranium Energy Corp. and Uranium Resources, Inc. since December 31, 2011, assuming that $100 was invested and, where applicable, includes the reinvestment of dividends.

 

Picture 8

 

 

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2011

2012

2013

2014

2015

2016

Ur-Energy Inc.

100

97

163

107

89

72

NYSE MKT Index

100

103

106

107

94

101

Russell 3000

100

114

149

165

162

179

Peer Average

100

72

61

51

27

28

 

 

 

 

Item 6.  SELECTED FINANCIAL DATA

 

The selected financial data set forth below are derived from our audited consolidated financial statements for the years ended December 31, 2016, 2015, 2014, 2013 and 2012, and should be read in conjunction with those financial statements and the notes thereto. The consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). Reference should also be made to “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.”

 

Summary of Financial Condition

 

(Amounts in thousands of U.S. Dollars except per share data) 

 

 

 

 

 

 

 

 

 

As of December 31

 

2016

2015

2014

2013

2012

Working capital (deficiency)

(1,706)
(7,510)
(2,645)
(242)
15,532

Current assets

6,506
5,713
9,346
10,432
18,210

Total assets

89,940
95,757
104,451
105,336
69,483

Current liabilities

8,212
13,223
11,991
10,674
2,678

Long-term liabilities

45,496
50,033
60,359
55,998
1,168

Shareholders' equity

36,232
32,501
32,101
38,664
65,637

 

 

 

 

 

 

 

 

 

 

Year ended December 31

 

2016

2015

2014

2013

2012

Revenue

27,305
41,877
29,349
7,616

Nil

Net loss for the year

(3,010)
(795)
(8,749)
(30,353)
(17,558)

 

 

 

 

 

 

Loss per common share:

    Basic and diluted

(0.02)
(0.01)
(0.07)
(0.25)
(0.15)

 

 

 

 

 

 

Cash dividends per common share

Nil

Nil

Nil

Nil

Nil

 

No dividends were paid during these five years.

 

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Item 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

 

Business Overview

 

The following discussion is designed to provide information that we believe necessary for an understanding of our financial condition, changes in financial condition and results of our operations. The following discussion and analysis should be read in conjunction with the accompanying audited consolidated financial statements and related notes. The financial statements have been prepared in accordance with US GAAP.

 

2016 Developments

 

Lost Creek Property – Great Divide Basin, Wyoming

 

Following receipt of the final regulatory authorization in October 2012, we commenced construction at Lost Creek. Construction included the plant facility and office building, installation of all process equipment, installation of two access roads, additional power lines and drop lines, deep disposal wells, construction of two holding ponds, warehouse building, and drill shed building. In August 2013, the Company was given operational approval by the NRC and commenced production operation activities.

Production operations in MU1 within the HJ Horizon began on August 2, 2013 and, through December 31, 2016, 2,108,095 pounds of uranium have been captured from this mine unit. For the Lost Creek PEA, all resources produced through September 30, 2015 were subtracted from total Measured Resources from the HJ Horizon in MU1 in order to accurately reflect remaining resources. All of the original wells as well as the planned 13 header houses (“HHs”) have been completed and are in operation.

All monitor ring wells have been installed and pump-tested in MU2 allowing for submittal of the appropriate operating permits. In addition, development work in the form of well, pipeline and infrastructure installation has various levels of completion in the first three header houses of MU2. Specifically, a majority of planned pattern wells have been piloted and cased within that area, the main trunkline has been installed to the first five header houses and the entirety of MU2 has been fenced. During 2016, project drilling was limited to wells related to permitting activities, recompletions and workovers, and other data gathering. All of these activities will allow for a quick turn-around to production once market fundamentals change. 

Two applications for amendments to the license and permits have been submitted; as described in the Lost Creek PEA, the two applications primarily seek to authorize production in the KM Horizon within the Lost Creek Project and to authorize production in the HJ and KM Horizons within the EMT in the LC East Project.

During 2016, the Company had 662,000 pounds under contract at an average price of $47.58. In the first quarter of 2016, a customer pushed the timing of two, high-priced, contract deliveries from the first half of the year to the second half of the year.  The contracts were for 100,000 pounds each at $62.00 per pound, which meant that $12.4 million of expected cash receipts shifted to the back half of the year. This created a cash flow timing issue for the Company. As a result, we completed two financing transactions.

 

In February 2016, we completed a bought deal financing for aggregate gross proceeds to the Company in the amount of $6.5 million.

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In March 2016, we assigned those two contract deliveries to a third party for cash proceeds of $5.1 million. These financing transactions resolved the cash flow timing issue brought about by the change in the contractual delivery dates.  Assigning the pounds to a third party also relieved the Company from any further delivery obligation on the assigned pounds, which allowed the Company the flexibility to either build inventory or sell into the spot market, as needed. The following table shows our contract and spot sales before and after the assignment:

 

 

 

 

 

 

 

 

 

 

U  3O8 Sales summary (1)

 

 

Pounds

 

Price per pound

 

Gross sales value

 

 

 

 

 

 

 

 

(thousands)

Contract sales before the assignment

 

 

662,000

 

$

47.58

 

$

31,516

Less assigned contract sales

 

 

(200,000)

 

$

62.00

 

$

(12,400)

Contract sales after the assignment

 

 

462,000

 

$

41.38

 

$

19,116

 

 

 

 

 

 

 

 

 

 

Spot sales

 

 

100,000

 

$

30.75

 

$

3,075

 

 

 

 

 

 

 

 

 

 

U  3O8 sales from production

 

 

562,000

 

$

39.49

 

$

22,191

   Note:

1 The above table includes non-GAAP measurements. See Reconciliation of Non-GAAP sales and inventory presentation with US GAAP statement presentation below.

From production, Lost Creek sold a total of 562,000 pounds U3O8  during 2016 at an average price of $39.49 per pound. After the assignment of the two contract deliveries to a third party, our remaining contract sales were 462,000 pounds at an average price of $41.38 per pound. Additionally, we sold 100,000 pounds into the spot market at an average price of $30.75 per pound.

During 2016, 538,004 pounds of U3O8 were captured within the Lost Creek plant; 561,094 pounds U3O8  were packaged in drums; and 579,179 pounds U3O8  of drummed inventory were shipped from the Lost Creek processing plant to the converter. At December 31, inventory at the conversion facility was approximately 84,689 pounds U3O8. Production levels for the year were lower than 2015 but were consistent with our anticipated contract and spot sales after taking into account the assigned contracts. 

A significant amount of work has been done to prepare MU2 for production. However, the uranium market and related uranium prices deteriorated significantly in 2016. As a result, we deliberately slowed additional development activities in MU2 and instead focused on enhancing production from the 13 operating header houses in MU1. During 2017, we plan to proceed with a controlled rate development of MU2, which will allow us to produce at a level that will satisfy a portion of our sales contracts.

Only one header house (HH 1-13) was brought on line in 2016. Following its commissioning, staff initiated refinements to other header houses and production processes based upon results at HH 1-13. After more than three years of operations, MU1 still produced a yearly average head grade of 58 ppm. However, the head grade during Q4 averaged 39 ppm. The lower head grade during this period of operation, as well as varying month-to-month grades, is a typical result as a mine matures and older operating patterns remain in the flow regime.

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Lost Creek Regulatory Proceedings

 

After receiving notice of final operational clearance from the NRC, we commenced production activities at Lost Creek in August 2013. Subsequent to those final approvals, we have made necessary additional filings for approvals of ongoing operations at Lost Creek (e.g., wellfield development; authorizations related to the new deep disposal well; permits and authority for new Class V wells).  In September 2014, we filed applications for amendment of all Lost Creek permits and licenses to include recovery from the KM horizon and LC East operations. In 2015, the BLM issued a notice of intent to complete an environmental impact statement for the application. The NRC will participate in this review as a cooperating agency. A permit amendment requesting approval to mine at the LC East Project and within the KM Horizon at the Lost Creek Project was also submitted to the WDEQ for review and approval. Approval will include an aquifer exemption. At this time, all of those applications continue through the regulatory process; we are responding to additional comments from the agencies, including providing data from additional monitor wells which were drilled for data-gathering purposes.

 

By the end of 2016, all general regulatory authorizations for Underground Injection Control (UIC) Class V wells have been completed for Lost Creek. Following receipt of the final such approval from NRC in September, we conducted pre-operational analyses and final testing, upon which final operational approvals were received from regulators in December 2016. These relatively shallow Class V wells will allow for the onsite recirculation of up to 200 gpm of fresh permeate (i.e., clean water) from operations. Site operators will use the reverse osmosis (RO) circuits, which were installed during initial construction of the plant, to process waste water into brine and permeate streams. The brine stream will continue to be disposed of in the UIC Class I deep wells while the clean, permeate stream will be injected into the UIC Class V wells. Subsequent to year’s end, the wells and RO system have been brought online and are now operational. We anticipate that this new water recycling system will enhance waste water disposition at the site.

 

Shirley Basin Project

 

In 2014, we commissioned and issued an independent, NI 43-101 technical report on Shirley Basin, reporting the initial mineral resource on the project. Subsequently, on January 27, 2015, we issued a second independent, NI 43-101 report on Shirley Basin: the “Preliminary Economic Assessment Shirley Basin Uranium Project Carbon County, Wyoming,” (“Shirley Basin PEA”). The Shirley Basin PEA suggests the possible viability of the project, based upon analyses of metallurgy and recoverability, engineering, and economics including costs of capital expenditures and operating costs. The mineral resources for the Shirley Basin Project were estimated in the Technical Report, and considered for economics and recoverability in the Shirley Basin PEA. The mineral resource estimate is set forth above, in Items 1 and 2. Business and Properties – Shirley Basin Project.

 

Baseline studies necessary for the permitting and licensing of the project commenced in 2014 and were completed in 2015. Subsequently, in December 2015, our application for a permit to mine was submitted to the WDEQ. While the Shirley Basin PEA contemplates that the Lost Creek processing facility may be utilized for the drying and packaging of uranium from Shirley Basin (for which we would currently anticipate the need only for a satellite plant) the Shirley Basin permit application contemplates the construction of a full processing facility, providing greater construction and operating flexibility as may be dictated by market conditions. 

 

In addition to the WDEQ application for permit to mine, work is well underway on other applications for all necessary authorizations to mine at Shirley Basin. We have watched with interest the development of the Wyoming “agreement state” program, by which the NRC will delegate its authority for source material licensure and other radiation safety issues to the WDEQ. We understand that the development of the Wyoming URP remains on schedule for full implementation and transition likely occurring in 2018. Based upon that timing,

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we currently anticipate submitting our application for a source material license for Shirley Basin to the State URP.

 

Under the terms of our acquisition of Pathfinder from AREVA in 2013, we were obligated to pay a five percent production royalty on production at the Shirley Basin Project under certain market conditions, if such conditions

were triggered prior to June 30, 2016. That contingent royalty was capped to the various triggers and could have been repurchased at our election. On June 30, 2016, the royalty lapsed and was terminated because the market conditions had not been triggered.

 

The Bootheel Project, LLC

 

In April 2016, the Management Committee of the Bootheel Project determined to continue the ownership and maintenance on the Bootheel property for the fiscal year ending March 31, 2017, which is the fiscal year end of The Bootheel Project, LLC. No additional exploration or development activities are expected at this time for 2017. Due to the continuing decline in the spot price of uranium combined with the reduction in minerals when the related lease was not renegotiated, the Company examined the valuation of the investment and determined that as a standalone investment, it had an insignificant value and was therefore fully impaired during 2016 resulting in a loss on investment of $1.1 million.

 

Other Mineral Properties

 

In June 2016, we elected to not renew our claims in the area known as the Hauber Project. As a result, we have written off our investment of $62 thousand in that project. We maintain the related geologic database for the project to support future activities if warranted. In addition to the claims at the Hauber Project and those mentioned above at the EN Project (Items 1 and 2), we also chose to abandon certain non-essential claims at other projects.  The carrying value of the properties affected by this decision was not affected.

 

Corporate Transactions and Financing Developments

 

Bought Deal Financing

 

In February 2016, we completed a bought deal financing in which a syndicate of investment dealers purchased 12,921,000 Common Shares at a purchase price of $0.50 per Common Share, for aggregate proceeds of $6.5 million.

 

At Market Financing

 

In May 2016, we entered into an At Market Issuance Sales Agreement with MLV & Co. LLC and FBR Capital Markets & Co. under which we may, from time to time, issue and sell Common Shares at market prices on the NYSE MKT or other U.S. market through the distribution agents for aggregate sales proceeds of up to $10,000,000. During 2016, we sold 164,979 Common Shares under the sales agreement. See discussion below under Material Changes in Financial Condition, Liquidity and Capital Resources.

 

RMB Australia Holdings Limited

 

We established a banking relationship with RMB Australia Holdings Limited (“RMB”) in 2013 which allowed for various financings during 2013. The first facility remained available for redraw as necessary for the Pathfinder acquisition, and $5.0 million was redrawn in December 2013 for that purpose. The facility was amended in March 2014 and an additional $1.5 million was drawn down at that time and, following the

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completion of the Technical Report (NI 43-101) on the Shirley Basin Project, an additional $3.5 million was drawn down as a revolver in September 2014.  In October 2015, the facility was amended to extend the maturity date of the $3.5 million revolver and spread the balance originally due March 2016 over four quarterly payments commencing March 2016 and concluding December 2016.  This loan was paid in full in December 2016.

 

Off Take Sales Agreements

 

As of December 31, 2016, we have multiple off take sales agreements with various U.S. utilities. These agreements were completed between 2012 and 2015 for deliveries between 2017 and 2021 as follows: 

 

 

 

SUMMARY OF OFF TAKE SALES AGREEMENTS

Production Year

Total Pounds Uranium Concentrates Contractually Committed

2017

600,000 pounds

2018

500,000 pounds

2019

600,000 pounds

2020

450,000 pounds

2021

250,000 pounds

 

Corporate Organization and Management

 

In December 2016, Jeffrey T. Klenda, our Chair and Acting Chief Executive Officer was appointed President and Chief Executive Officer of the Company.  Mr. Klenda is a founding director of the Company and has served as Executive Director and Chairman since 2006. He also will continue to serve as the Chairman of the Board of Directors.

 

In June 2016, reductions in workforce were implemented due to continuing depressed uranium market conditions. Twelve employees were laid off, and several other employees were asked to change job responsibilities or carry additional responsibilities. Operations at Lost Creek proceeded uninterrupted. A further, smaller, reduction in force has been implemented in 2017; again, the focus was on those departments not directly related to production.

 

 

2016 Results of Operations

 

U3O8 Production Costs

 

During 2016, 538,004 pounds of U3O8 were captured within the Lost Creek plant. A total of 561,094 pounds were packaged in drums and 579,179 pounds of the drummed inventory were shipped to the conversion facility where 562,000 pounds were sold to utility customers. The cash cost per pound and non-cash cost per pound for produced uranium presented in the following Production Costs and U3O8 Sales and Cost of Sales tables are non-US GAAP measures. These measures do not have a standardized meaning within US GAAP or a defined basis of calculation. These measures are used by management to assess business performance and determine production and pricing strategies. They may also be used by certain investors to evaluate performance. Please

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see the tables, below, for reconciliations of these measures to the US GAAP compliant financial measures.  Production figures for the Lost Creek Project are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and Production Costs

 

Unit

 

2016 Q4

 

2016 Q3

 

2016 Q2

 

2016 Q1

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pounds captured

 

lb

 

 

103,558

 

 

141,774

 

 

133,341

 

 

159,331

 

 

538,004

 

Ad valorem and severance tax

 

$000

 

$

247

 

$

552

 

$

304

 

$

420

 

$

1,523

 

Wellfield cash cost (1)

 

$000

 

$

864

 

$

858

 

$

846

 

$

1,013

 

$

3,581

 

Wellfield non-cash cost (2)

 

$000

 

$

777

 

$

778

 

$

778

 

$

731

 

$

3,064

 

Ad valorem and severance tax per pound captured

 

$/lb

 

$

2.39

 

$

3.89

 

$

2.28

 

$

2.64

 

$

2.83

 

Cash cost per pound captured

 

$/lb

 

$

8.34

 

$

6.05

 

$

6.34

 

$

6.36

 

$

6.66

 

Non-cash cost per pound captured

 

$/lb

 

$

7.50

 

$

5.49

 

$

5.83

 

$

4.59

 

$

5.70

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pounds drummed

 

lb

 

 

111,049

 

 

145,893

 

 

130,308

 

 

173,844

 

 

561,094

 

Plant cash cost (3)

 

$000

 

$

1,336

 

$

1,564

 

$

1,505

 

$

1,696

 

$

6,101

 

Plant non-cash cost (2)

 

$000

 

$

493

 

$

494

 

$

494

 

$

497

 

$

1,978

 

Cash cost per pound drummed

 

$/lb

 

$

12.03

 

$

10.72

 

$

11.55

 

$

9.76

 

$

10.87

 

Non-cash cost per pound drummed

 

$/lb

 

$

4.44

 

$

3.39

 

$

3.79

 

$

2.86

 

$

3.53

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pounds shipped to conversion facility

 

lb

 

 

98,775

 

 

149,540

 

 

148,714

 

 

182,150

 

 

579,179

 

Distribution cash cost (4)

 

$000

 

$

68

 

$

86

 

$

123

 

$

88

 

$

365

 

Cash cost per pound shipped

 

$/lb

 

$

0.69

 

$

0.58

 

$

0.83

 

$

0.48

 

$

0.63

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Notes:

1.

Wellfield cash costs include all wellfield operating costs. Wellfield construction and development costs, which include wellfield drilling, header houses, pipelines, power lines, roads, fences and disposal wells, are treated as development expense and are not included in wellfield operating costs.

2.

Non-cash costs include the amortization of the investment in the mineral property acquisition costs and the depreciation of plant equipment, and the depreciation of their related asset retirement obligation costs. The expenses are calculated on a straight line basis so the expenses are typically constant for each quarter. The cost per pound from these costs will therefore typically vary based on production levels only.

3.

Plant cash costs include all plant operating costs and site overhead costs.

4.

Distribution cash costs include all shipping costs and costs charged by the conversion facility for weighing, sampling, assaying and storing the U3O8 prior to sale.

 

Production costs have remained fairly consistent over the past four quarters while the production costs per pound generally increased during the year. In total, wellfield, plant and distribution cash costs were very consistent quarter on quarter during 2016. The respective cash costs per pound increased overall during the year and the increases were primarily driven by decreasing levels of production. 

 

Ad valorem and severance taxes fluctuate based on pounds extracted and the related sales value of those pounds.  The increase in ad valorem and severance taxes during the third quarter was due to an increase to the ad valorem tax rate that was announced during the quarter. Fluctuations in the ad valorem and severance taxes per pound in the other quarters were primarily due to fluctuations in the average price per pound sold during those same quarters.

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Wellfield cash costs in 2016 Q1 were somewhat elevated due to some non-recurring expenses and the annual labor bonus. They then decreased significantly in 2016 Q2 and remained at normal levels in the last two quarters. The average cash cost per pound captured increased to $8.34 2016 Q4 and averaged $6.66 for the year, as compared to $5.00 in 2015. The increase was due to lower average production levels during the year. As previously discussed, production levels were deliberately maintained at levels sufficient to satisfy our expected contract and spot sales in light of the depressed uranium market. Wellfield non-cash costs were relatively fixed during the year, which is typical. The resulting non-cash cost per pound captured increased to $7.50 in 2016 Q4 and averaged $5.70 for the year, as compared to $5.58 in 2016. Again, the increase was due to lower production levels.

 

Plant cash costs generally decreased during the year with the higher costs in 2016 Q1 being driven by the annual labor bonus. Despite the lower cash costs, the resulting cash cost per pound drummed increased to $12.03 in 2016 Q4 as a result of lower production and averaged $10.87 for the year, as compared to $9.92 in 2015.  Plant non-cash costs did not change during the year. The non-cash cost per pound drummed increased to $4.44 in 2016 Q4 and averaged $3.53 for the year, as compared to $2.74 in 2015. The increase was again due to lower production rates.

 

With the exception of 2016 Q2, distribution costs decreased during the year, as did pounds shipped. The resulting cash cost per pound shipped in 2016 Q4 increased to $0.69 and averaged $0.63 per pound for the year, as compared to $0.69 in 2015.

 

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U3O8 Sales and Cost of Sales

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales and cost of sales

 

Unit

 

2016 Q4

 

2016 Q3

 

2016 Q2

 

2016 Q1

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pounds sold

 

lb

 

 

100,000

 

 

200,000

 

 

187,000

 

 

75,000

 

 

562,000

U3O8 sales

 

$000

 

$

3,270

 

$

9,471

 

$

6,741

 

$

2,709

 

$

22,191

Average contract price

 

$/lb

 

$

32.70

 

$

47.36

 

$

39.35

 

$

39.35

 

$

41.38

Average spot price

 

$/lb

 

$

 -

 

$

 -

 

$

27.00

 

$

34.50

 

$

30.75

Average price per pound sold

 

$/lb

 

$

32.70

 

$

47.36

 

$

36.05

 

$

36.12

 

$

39.49

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U3O8 cost of sales (1)

 

$000

 

$

3,082

 

$

5,818

 

$

5,094

 

$

1,855

 

$

15,849

Ad valorem and severance tax cost per pound sold

 

$/lb

 

$

2.98

 

$

3.09

 

$

2.65

 

$

2.61

 

$

2.86

Cash cost per pound sold

 

$/lb

 

$

18.27

 

$

17.50

 

$

16.88

 

$

15.41

 

$

17.15

Non-cash cost per pound sold

 

$/lb

 

$

9.57

 

$

8.50

 

$

7.71

 

$

6.71

 

$

8.19

Average cost per pound sold

 

$/lb

 

$

30.82

 

$

29.09

 

$

27.24

 

$

24.73

 

$

28.20

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U3O8 gross profit

 

$000

 

$

188

 

$

3,653

 

$

1,647

 

$

854

 

$

6,342

Gross profit per pound sold

 

$/lb

 

$

1.88

 

$

18.27

 

$

8.81

 

$

11.39

 

$

11.29

Gross profit margin

 

%

 

 

5.7%

 

 

38.6%

 

 

24.4%

 

 

31.5%

 

 

28.6%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ending Inventory Balances

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pounds

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In-process inventory

 

lb

 

 

29,891

 

 

57,647

 

 

62,028

 

 

71,602

 

 

 

Plant inventory

 

lb

 

 

12,274

 

 

 -

 

 

3,654

 

 

22,062

 

 

 

Conversion facility inventory

 

lb

 

 

84,689

 

 

84,808

 

 

135,723

 

 

173,178

 

 

 

Total inventory

 

lb

 

 

126,854

 

 

142,455

 

 

201,405

 

 

266,842

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total cost

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In-process inventory

 

$000

 

$

897

 

$

866

 

$

929

 

$

977

 

 

 

Plant inventory

 

$000

 

$

461

 

$

 -

 

$

115

 

$

569

 

 

 

Conversion facility inventory

 

$000

 

$

2,751

 

$

2,539

 

$

3,846

 

$

4,388

 

 

 

Total inventory

 

$000

 

$

4,109

 

$

3,405

 

$

4,890

 

$

5,934

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost per pound

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In-process inventory

 

$/lb

 

$

30.01

 

$

15.02

 

$

14.98

 

$

13.64

 

 

 

Plant inventory

 

$/lb

 

$

37.56

 

$

 -

 

$

31.47

 

$

25.79

 

 

 

Conversion facility inventory

 

$/lb

 

$

32.48

 

$

29.94

 

$

28.32

 

$

25.34

 

 

 

 

Note:

1.

Costs of sales include all production costs (notes 1, 2, 3 and 4 in the previous Production and Production Costs table) adjusted for changes in inventory values.

 

U3O8 sales in 2016 Q4 were based on selling 100,000 pounds at an average price per pound of $32.70. The sale was in to one of our lower-priced contracts for the year. For the year, we sold 562,000 pounds at an average price per pound of $39.49 for total uranium sales of $22.2 million.  Total 2016 contract deliveries were 662,000

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pounds at an average price per pound of $47.58.  As discussed above two 100,000 pound contracts at $62 per pound were assigned to a third party for net cash proceeds of $5.1 million.

 

In 2016 Q4, our cost of sales totaled $3.1 million based on selling 100,000 pounds from production at an average cost per pound of $30.82.  For the year, our average cost per pound sold averaged $28.20, as compared to $29.53 in 2015.  In 2015, the cost per pound sold trended down as production levels increased and in 2016, the cost per pound sold trended up as production levels decreased. As stated before, our cost per pound sold will tend to decrease as our production levels increase, and increase as our production levels decrease, so long as our production costs remain relatively stable, which has been the case.

 

The gross profit from uranium sales for 2016 Q4 was $0.2 million, which represents a gross profit margin of approximately six percent. This was lower than previous quarters due to the lower sales prices and higher cost per pound sold during the quarter. For the year, the gross profit from uranium sales was $6.3 million and the average gross profit margin was 29%, as compared to 30% in 2015.

 

At the end of the year, we had approximately 84,689 pounds of U3O8 at the conversion facility at an average cost per pound of $32.48. The following table shows the average cost per pound of the conversion facility pounds.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ending Conversion Facility Inventory Cost Per Pound Summary

 

Unit

   

 

 

 

 

 

 

 

 

 

 

 

 

 

31-Dec-16

 

30-Sep-16

 

30-Jun-16

 

31-Mar-16

Ad valorem and severance tax cost per pound

 

$/lb

 

$

2.72

 

$

3.30

 

$

2.68

 

$

2.57

Cash cost per pound

 

$/lb

 

$

19.44

 

$

17.80

 

$

17.50

 

$

15.85

Non-cash cost per pound

 

$/lb

 

$

10.32

 

$

8.84

 

$

8.14

 

$

6.92

Total cost per pound

 

$/lb

 

$

32.48

 

$

29.94

 

$

28.32

 

$

25.34

 

Generally, the cost per pound in ending inventory at the conversion facility increased during the year. The increase was directly related to the lower production figures as production costs were relatively consistent, or decreasing slightly, during the year.

 

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Annual Results Comparison

 

The following table presents and annual comparison of a portion of the above information for the years ended December 31, 2016, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

Comparison of annual results

Unit

 

2016

 

2015

 

2014

Sales

 

 

 

 

 

 

 

 

 

 

 

Sales per financial statements

 

$000

 

$

27,297

 

$

41,877

 

$

29,349

Less disposal fees

 

$000

 

$

(20)

 

$

(69)

 

$

(323)

Less gain from sale of deliveries under contract

$000

 

$

(5,086)

 

$

 -

 

$

(2,507)

U3O8 sales

 

$000

 

$

22,191

 

$

41,808

 

$

26,519

 

 

 

 

 

 

 

 

 

 

 

 

Cost of sales

 

 

 

 

 

 

 

 

 

 

 

Ad valorem & severance taxes

$000

 

$

1,523

 

$

1,604

 

$

2,425

Wellfield costs

$000

 

$

6,645

 

$

8,291

 

$

9,399

Plant and site costs

$000

 

$

8,079

 

$

9,202

 

$

8,799

Distribution costs

$000

 

$

365

 

$

494

 

$

350

Inventory change

$000

 

$

(763)

 

$

1,823

 

$

(3,115)

Cost of sales - produced

$000

 

$

15,849

 

$

21,414

 

$

17,858

Cost of sales - purchased

$000

 

$

 -

 

$

7,878

 

$

 -

Total cost of sales

$000

 

$

15,849

 

$

29,292

 

$

17,858

 

 

 

 

 

 

 

 

 

 

 

 

Gross profit from U3O8 sales

 

$000

 

$

6,342

 

$

12,516

 

$

8,661

 

 

 

 

 

 

 

 

 

 

 

 

Production

 

 

 

 

 

 

 

 

 

 

 

Pounds extracted

 

lb

 

 

538,004

 

 

783,547

 

 

596,176

Pounds drummed

 

lb

 

 

561,094

 

 

727,245

 

 

547,992

Pounds shipped

 

lb

 

 

579,179

 

 

717,125

 

 

562,533

 

 

 

 

 

 

 

 

 

 

 

 

Pounds sold - produced

 

lb

 

 

562,000

 

 

725,000

 

 

517,760

Pounds sold - purchased

 

lb

 

 

 -

 

 

200,000

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

Per Pound Sold

 

 

 

 

 

 

 

 

 

 

 

Average contract price

 

$/lb

 

$

41.38

 

$

49.42

 

$

51.22

Average spot price

 

$/lb

 

$

30.75

 

$

36.18

 

$

 -

Average price

 

$/lb

 

$

39.49

 

$

45.20

 

$

51.22

 

 

 

 

 

 

 

 

 

 

 

 

Ad valorem and severance tax

$/lb

 

$

2.86

 

$

3.14

 

$

2.48

Cash cost

 

$/lb

 

$

17.15

 

$

16.27

 

$

19.73

Non-cash cost

 

$/lb

 

$

8.19

 

$

10.12

 

$

12.28

Cost - Produced

 

$/lb

 

$

28.20

 

$

29.53

 

$

34.49

Cost - Purchased

 

$/lb

 

$

 -

 

$

39.39

 

$

 -

 

 

 

 

 

 

 

 

 

 

 

 

Average cost

 

$/lb

 

$

28.20

 

$

31.67

 

$

34.49

 

 

 

 

 

 

 

 

 

 

 

 

Gross profit (1)

 

$/lb

 

$

11.29

 

$

13.53

 

$

16.73

 

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Note:

1.

For comparative purposes, gross profit and gross profit per pound for the years 2014 and 2016 exclude the profit recognized on the assignment of deliveries.

 

Through 2015, the volume of pounds captured, drummed and shipped steadily increased as issues associated with the start-up of operations were addressed and remediated. Similarly, the cash costs and non-cash costs continued to decrease on a per pound basis as most of our operating expenses are fixed, so greater production continues to lead to lower costs per pound. The sole exception is ad valorem and severance taxes which are based on industry factors and tax rates determined by the state as well as the average sales price we receive for the sale of U3O8. In 2014, the state significantly increased the industry factor for extraction, then subsequently revised it to a lower amount in early 2015. As a result, the rate has varied between years, but should begin to stabilize as the industry factor is set for several years, however the taxes paid may still vary due to changes in the average sales price received and volume of pounds extracted.

 

In 2016, our production levels decreased as we produced at rates consistent with our anticipated contract and spot sales after taking into account the assigned contracts. As a result, we only needed to bring one header house (HH 1-13) on line during the year. We continued to produce from the other 12 header houses during the year, although at declining rates, which is a typical result as the mine matures and older operating patterns remain in the flow regime. Our costs in 2016 were either consistent with or lower than previous years, which resulted in a lower, over-all, cost per pound sold average for the year; going from $29.53 per pound sold from production in 2015 to $28.20 in 2016. The cost per pound sold from production was trending up at the end of the year and will continue to do so until production rates are returned to higher levels.

 

As discussed previously, we are continuously surveying the market for opportunities to create future, long-term, contracts at favorable rates. However, long-term pricing weakened during 2016 and we did not enter into any new contracts during 2016. But as discussed above, the Company maintains a good book of contracts into 2021. Our 2014 and 2015 contract prices averaged $50 per pound, which was what we had targeted. Our average contract price in 2016 was also close to $50 per pound for the 662,000 pounds we had under contract.  However, as noted, we assigned two of the higher priced contracts to a third party, which left 462,000 pounds to be sold into contracts at an average price of $41.38 per pound. Additionally, in 2016, we also made spot sales into a weaker market as compared to 2015 (there were no spot sales in 2014), which resulted in a reduction of our average sales price as well as our average gross profit per pound despite reducing our per pound costs.

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Reconciliation of Non-GAAP sales and inventory presentation with US GAAP statement presentation

 

As discussed above, the cash costs, non-cash costs and per pound calculations are non-US GAAP measures we use to assess business performance. To facilitate a better understanding of these measures, the tables below present a reconciliation of these measures to the financial results as presented in our financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Price Per Pound Sold Reconciliation

 

Unit

 

2016 Q4

 

2016 Q3

 

2016 Q2

 

2016 Q1

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales per financial statements

 

$000

 

$

5,776

 

$

12,068

 

$

6,747

 

$

2,714

 

$

27,305

Less disposal fees

 

$000

 

$

(9)

 

$

(9)

 

$

(6)

 

$

(5)

 

$

(29)

Less revenue from sale of deliveries under contract

 

$000

 

$

(2,497)

 

$

(2,588)

 

$

 -

 

$

 -

 

$

(5,085)

U3O8 sales

 

$000

 

$

3,270

 

$

9,471

 

$

6,741

 

$

2,709

 

$

22,191

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total pounds sold

 

lb

 

 

100,000

 

 

200,000

 

 

187,000

 

 

75,000

 

 

562,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average price per pound sold

 

$/lb

 

$

32.70

 

$

47.36

 

$

36.05

 

$

36.12

 

$

39.49

 

The Company delivers U3O8 to a conversion facility and receives credit for a specified quantity measured in pounds once the product is confirmed to meet the required specifications. When a delivery is approved, the Company notifies the conversion facility with instruction for a title transfer to the customer. Revenue is recognized once a title transfer of the U3O8 is confirmed by the conversion facility.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Cost Per Pound Sold

Reconciliation 1

 

Unit

 

2016 Q4

 

2016 Q3

 

2016 Q2

 

2016 Q1

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ad valorem & severance taxes

 

$000

 

$

247

 

$

552

 

$

304

 

$

420

 

$

1,523

Wellfield costs

 

$000

 

$

1,641

 

$

1,636

 

$

1,624

 

$

1,744

 

$

6,645

Plant and site costs

 

$000

 

$

1,829

 

$

2,059

 

$

1,998

 

$

2,193

 

$

8,079

Distribution costs

 

$000

 

$

68

 

$

86

 

$

123

 

$

88

 

$

365

Inventory change

 

$000

 

$

(704)

 

$

1,485

 

$

1,045

 

$

(2,590)

 

$

(764)

Total cost of sales

 

$000

 

$

3,081

 

$

5,818

 

$

5,094

 

$

1,855

 

$

15,848

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total pounds sold

 

lb

 

 

100,000

 

 

200,000

 

 

187,000

 

 

75,000

 

 

562,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total average cost per pound sold

 

$/lb

 

$

30.82

 

$

29.09

 

$

27.24

 

$

24.73

 

$

28.20

Note:

1.

The cost per pound sold reflects both cash and non-cash costs, which are combined as cost of sales in the statement of operations included in this filing. The cash and non-cash cost components are identified in the above production cost table.

 

The cost of sales includes ad valorem and severance taxes related to the extraction of uranium, all costs of wellfield, plant and site operations including the related depreciation and amortization of capitalized assets, reclamation and mineral property costs, plus product distribution costs. These costs are also used to value inventory and the resulting inventoried cost per pound is compared to the estimated sales prices based on the

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contracts or spot sales anticipated for the distribution of the product. Any costs in excess of the calculated market value are charged to cost of sales.

 

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

 

The following table summarizes the results of operations for the years ended December 31, 2016 and 2015 (in thousands of U.S. dollars):

 

 

 

 

 

 

Year ended December 31,

 

2016

 

2015

 

$

 

$

 

 

 

 

Sales

27,305

 

41,877

Cost of sales

(15,848)

 

(29,292)

Gross profit

11,457

 

12,585

Exploration and evaluation expense

(2,964)

 

(2,853)

Development expense

(2,886)

 

(5,358)

General and administrative expense

(4,740)

 

(5,715)

Accretion expense

(534)

 

(515)

Write-off of mineral properties

(62)

 

 -

Net profit (loss) from operations

271

 

(1,856)

Interest expense (net)

(1,977)

 

(2,557)

Warrant mark to market gain

36

 

307

Loss from equity investment

(5)

 

(8)

Write-off of equity investments

(1,089)

 

 -

Foreign exchange loss

(278)

 

(1)

Other income

15

 

5

Loss before income taxes

(3,027)

 

(4,110)

Income tax recovery (net)

17

 

3,315

Net loss

(3,010)

 

(795)

 

 

 

 

Loss per share – basic and diluted

(0.02)

 

(0.01)

 

 

 

 

Revenue per pound sold

39.49

 

45.20

 

 

 

 

Total cost per pound sold

28.20

 

31.67

 

 

 

 

Gross profit per pound sold

11.29

 

13.53

 

Sales

 

We sold a total of 562,000 pounds of U3O8 from production during the year ended December 31, 2016 for an average price of $39.49 per pound as compared to 2015 when we sold 925,000 pounds for an average price of $45.20. The fluctuation in sales prices relates primarily to lower priced spot sales made in 2016. In 2016, we assigned two contract deliveries totaling 200,000 pounds of U3O8  to a third-party trader. The deliveries were made during the year and we recognized $5.1 million in sales from those contracts.  The sales in 2015 included the sale of 200,000 pounds of U3O8  which were purchased from a third-party trader.

 

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For the year ended December 31, 2016, we recognized $29 thousand compared to $69 thousand from disposal fees during 2015. 

 

Cost of Sales

 

The cost of sales includes all costs of wellfield operations and maintenance, severance and ad valorem taxes, plant operations and maintenance and mine site overhead including depreciation on the related capital assets, capitalized reclamation costs and amortization of mineral property costs, the cost of inventory purchased for resale and distribution costs. Wellfield costs, plant costs, site overhead costs and distribution costs are included in inventory and the resulting inventoried cost per pound is compared to the estimated sales prices based on the contracts or spot sales anticipated for the distribution of the product. Any costs in excess of the calculated market value are charged to expense.

 

As compared to 2015, our cost per pound sold decreased $3.47 to $28.20 in 2016. The year 2015 includes one sale of purchased product, which was at a cost of $39.39 per pound. Excluding this sale, the 2015 cost per pound sold from produced inventory was $29.53, which adjusts the 2016 cost per pound sold to a decrease of $1.33 per pound from 2015. 

 

The reduction in our cost per pound sold from produced inventory is primarily a function of decreased non-cash costs in 2016 as compared to 2015 resulting from the accelerated depreciation of capitalized reclamation costs attributable to MU1. As stated in previous filings, most of our production costs are relatively fixed. Therefore, decreased production in 2016 yielded higher cash costs per pound.

 

Gross Profit 

 

The gross profit from uranium sales was $6.3 million for the year ended December 31, 2016, which represents a gross profit margin of approximately 29%.  Gross profits of $12.5 million in 2015 represents a gross profit margin of approximately 30%. The primary reason for the decrease in the gross profit margin was the lower-priced spot sales in 2016, which more than offset the decrease in the cost per pound sold. 

 

Operating Expenses

 

Total operating expenses for the year ended December 31, 2016 were $11.2 million. Operating expenses include exploration and evaluation expense, development expense, G&A expense and mineral property write-offs. These expenses decreased by $3.2 million compared to 2015.

 

Exploration and evaluation expense consists of labor and the associated costs of the exploration and evaluation departments as well as land holding and exploration costs including drilling and analysis on properties which have not reached the permitting or operations stage. These expenses increased $0.1 million for the year ended December 31, 2016 compared to 2015. All costs associated with the geology and geological information systems departments as well as the costs incurred on specific projects as described above are reflected in this category. Costs increased due to higher labor related costs.

 

Development expense includes $2.4 million of costs incurred at the Lost Creek Project not directly attributable to production activities, including wellfield construction, drilling and development costs. It also includes $0.5 million of costs associated with the Shirley Basin and Lucky Mc properties which are considered development properties as they previously reached the permitting stage or operations stage. Development expenses decreased by $2.5 million in the year ended December 31, 2016 compared to 2015. The decrease was primarily related to the deferral of development activities at Lost Creek in response to depressed uranium prices.

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G&A expense relates to administration, finance, investor relations, land and legal functions and consists principally of personnel, facility and support costs. Expenses decreased by $1.0 million for the year ended December 31, 2016 compared to 2015. The decrease was due to reduced external consulting and legal expenses of $0.3 million combined with $0.6 million in lower labor costs due to reductions in force.

 

Other Income and Expenses

 

Net interest expense declined $0.6 million during 2016 compared to the prior year. The decline was due to a reduction in the outstanding principal which was slightly offset by increases in the interest rate on the RMB debt, which was tied to the quarterly LIBOR rate.

 

In December 2013, the Company sold equity units which included one Common Share and one-half warrant for the purchase of stock at $1.35 per Common Share. As the warrants were priced in U.S. dollars and not Canadian dollars, which is the currency of the Company’s Common Shares, these warrants are considered a derivative and are therefore treated as a liability. The gain for 2016 represents the balance of the liability at December 31, 2015 which was written off in 2016 as the warrants expired without being exercised in 2016.

 

In April 2016, the Management Committee of the Bootheel Project determined to continue the ownership and maintenance on the Bootheel property for the fiscal year ending March 31, 2017, which is the fiscal year end of The Bootheel Project, LLC. No additional exploration or development activities are expected at this time for 2017. Due to the continuing decline in the spot price of uranium combined with the reduction in minerals when the related lease was not renegotiated, the Company examined the valuation of the investment and determined that as a standalone investment, it had an insignificant value and was therefore fully impaired during 2016 resulting in a loss on investment of $1.1 million.

 

Income tax recovery

 

When we acquired Pathfinder in 2013, we recorded a deferred income tax liability as the Pathfinder assets had no tax basis and accounting guidance indicated that the potential liability should be recorded due to Pathfinder not being integrated into our operations and the likelihood that Pathfinder would have a going concern issue as a stand-alone entity.  The costs were capitalized as a part of the mineral property acquisition costs and will be amortized for reporting purposes once production commences. The amortization will not be deductible for tax reporting, therefore creating a permanent book versus tax difference.

 

We did preliminary drilling and baseline testing in 2014, and we filed our permit application with the WDEQ in 2015, therefore demonstrating the intent of incorporating uranium recovery operations at Shirley Basin into our other ongoing operations within the next few years pending the approval of the permit application. As Pathfinder was integrated into our operations, the guidance was no longer applicable and we used a portion of our accumulated net operation losses to offset the liability in 2015. The filing of the permit is an indication that the offset will be used within a few years and is therefore more probable than not that it will be used.

 

Loss per Common Share

 

The basic and diluted losses per Common Share for the year ended December 31, 2016 was $0.02 compared to a loss of $0.01 in 2015. The diluted loss per Common Share is equal to the basic loss per Common Share due to the anti-dilutive effect of all convertible securities outstanding given that net losses were experienced.

 

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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

 

The following table summarizes the results of operations for the years ended December 31, 2015 and 2014 (in thousands of U.S. dollars):

 

 

 

 

Year ended December 31,

 

2015

2014

 

$

$

Revenue

41,877
29,349

Cost of revenues

(29,292)
(17,858)

Gross profit

12,585
11,491

Exploration and evaluation expense

(2,853)
(3,277)

Development expense

(5,358)
(7,672)

General and administrative expense

(5,715)
(6,541)

Accretion expense

(515)
(497)

 

 

 

Write-off of mineral properties

 -

(483)

Net loss from operations

(1,856)
(6,979)

Interest income (expense) (net)

(2,557)
(2,699)

Mark to market loss

307
946

Loss from equity investment

(8)
(5)

Foreign exchange gain (loss)

(1)
(12)

Other income (loss

5

 -

Net loss

(4,110)
(8,749)

 

 

 

 

 

 

Loss per share – basic and diluted

(0.01)
(0.07)

 

Sales

 

We sold a total of 925,000 pounds of U3O8 during the year ended December 31, 2015 for an average price of $45.20 per pound as compared to 2014 when we sold 517,760 pounds for an average price of $51.22. The fluctuation in sales prices relates primarily to lower priced spot sales made in 2015.

 

For the year ended December 31, 2015, we recognized $70 thousand compared to $323 thousand from disposal fees during 2014.  In 2014, we also recognized sales of $2.5 million from deliveries under off take agreements which had been assigned to a third party for cash consideration during 2013.

 

Cost of Sales

 

The cost of sales includes all costs of wellfield operations and maintenance, severance and ad valorem taxes, plant operations and maintenance and mine site overhead including depreciation on the related capital assets, capitalized reclamation costs and amortization of mineral property costs, the cost of inventory purchased for resale and distribution costs. Wellfield costs, plant costs, site overhead costs and distribution costs are included in inventory and the resulting inventoried cost per pound is compared to the estimated sales prices based on the contracts or spot sales anticipated for the distribution of the product. Any costs in excess of the calculated market value are charged to expense.

 

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As compared to 2014, our cost per pound sold decreased $2.82 to $31.67 in 2015. The year 2015 includes one sale of purchased product, which was at a cost of $39.39 per pound. Excluding this sale, our cost per pound sold from produced inventory was $29.53, which represents a decrease from 2014 of $4.95 per pound. 

 

The reduction in our cost per pound sold from produced inventory is primarily a function of increased production in 2015 as compared to 2014. As stated in previous filings, most of our production costs are relatively fixed. Therefore, increased production yields lower costs per pound which is reflected in our operations during 2015.

 

Gross Profit 

 

The gross profit from uranium sales was $12.5 million for the year ended December 31, 2015, which represents a gross profit margin of approximately 30%.  Gross profits of $11.5 million in 2014 included $2.5 million from the delivery of uranium by a third party that related to contractual delivery commitments from 2013. Excluding these deferred revenues, the gross profit from uranium sales was $8.7 million, which represents a gross profit margin of approximately 33%. The primary reason for the decrease in the gross profit margin was the lower-priced spot sales in 2015, which more than offset the decrease in the cost per pound sold.  Generally, cost per pound sold declined with the exception of the purchased inventory which was at a higher cost per pound than the cost to produce and therefore also negatively affected the gross profit percentage in 2015.

 

Operating Expenses

 

Total operating expenses for the year ended December 31, 2015 were $14.4 million. Operating expenses include exploration and evaluation expense, development expense, G&A expense and mineral property write-offs. These expenses decreased by $4.0 million compared to 2014 which included costs associated with developing an additional disposal well and a potential severance liability that was recorded.

 

Exploration and evaluation expense consists of labor and the associated costs of the exploration and evaluation departments as well as land holding and exploration costs including drilling and analysis on properties which have not reached the permitting or operations stage. These expenses decreased $0.4 million for the year ended December 31, 2015 compared to 2014. All costs associated with the geology and geological information systems departments as well as the costs incurred on specific projects as described above are reflected in this category. Costs decreased due to a reduction in land lease costs associated with the Mustang property which was abandoned in 2014 as well as a decrease in labor related costs.

 

Development expense includes costs of $4.5 million incurred at the Lost Creek Project not directly attributable to production activities, including wellfield construction, drilling and development costs. It also includes $0.9 million of costs associated with the Shirley Basin and Lucky Mc properties as they previously reached the permitting stage or operations stage. Development expenses decreased by $2.3 million in the year ended December 31, 2015 compared to 2014.  The decrease was primarily related to the cost of a disposal well which was constructed in 2014.

 

G&A expense relates to administration, finance, investor relations, land and legal functions and consists principally of personnel, facility and support costs. Expenses decreased by $0.8 million for the year ended December 31, 2015 compared to 2014. The decrease was due to reduced external consulting and legal expenses of $0.3 million combined with $0.5 million in lower labor costs.

 

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Other Income and Expenses

 

Net interest expense declined $0.1 million during 2015 compared to the prior year. The decline was primarily due to a reduction in the outstanding principal which was slightly offset by increases in the interest rate on the RMB debt which is tied to the quarterly LIBOR rate.

 

In December 2013, the Company sold equity units which included one Common Share and one half warrant for the purchase of stock at US$1.35 per Common Share. As the warrants were priced in U.S. dollars and not Canadian dollars, which is the currency of the Company’s Common Shares, these warrants are considered a derivative and are therefore treated as a liability. The gains declined by $0.6 million for the year ended December 31, 2015 compared to 2014 based on changes in the exchange rates and the other factors used in the calculation of Black Scholes valuations which are not directly related to the Company’s results of operations.  The gain or loss will continue to decline as the warrants near expiry as changes in the exchange rates and a shorter volatility period continue to decrease the total liability.

 

Income Tax Recovery

 

When we acquired Pathfinder in 2013, we recorded a deferred income tax liability as the Pathfinder assets had no tax basis and accounting guidance indicated that the potential liability should be recorded due to Pathfinder not being integrated into our operations and would have a going concern issue as a stand-alone entity.  The costs were capitalized as a part of the mineral property acquisition costs and will be amortized for reporting purposes once production commences. The amortization will not be deductible for tax reporting therefore creating a permanent book versus tax difference.

 

We did preliminary drilling and baseline testing in 2014, and we filed our permit application with the WDEQ in 2015, therefore demonstrating the intent of incorporating the uranium recovery operations into our other ongoing operations within the next few years pending the approval of the permit application. As Pathfinder is being integrated into our operations, the guidance was no longer applicable and we used a portion of our accumulated net operation losses to offset the liability. The filing of the permit is an indication that the offset will be used within a few years and is therefore more probable than not that it will be used.

 

Loss per Common Share

 

The basic and diluted losses per Common Share for the year ended December 31, 2015 was $0.01 compared to a loss of $0.07 in 2014. The diluted loss per Common Share is equal to the basic loss per Common Share due to the anti-dilutive effect of all convertible securities outstanding given that net losses were experienced.

 

Material Changes in Financial Condition, Liquidity and Capital Resources

 

As at December 31, 2016, we had cash resources, consisting of cash and cash equivalents, of $1.6 million, an increase of $0.2 million from the December 31, 2015 balance of $1.4 million. The cash resources consist of Canadian and U.S. dollar denominated deposit accounts, money market funds and certificates of deposit.  We generated $3.3 million from operations during the year ended December 31, 2016. During the same period, we used $0.3 million for investing activities and $3.0 million for financing activities.

 

On October 23, 2013, we closed a $34.0 million Sweetwater County, State of Wyoming, Taxable Industrial Development Revenue Bond financing program (“State Bond Loan”).  The State Bond Loan calls for payments of interest at a fixed rate of 5.75% per annum on a quarterly basis which commenced January 1, 2014. The principal is payable in 28 quarterly installments which commenced January 1, 2015 and continue through

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October 1, 2021. The State Bond Loan is secured by all of the assets at the Lost Creek Project. As of December 31, 2016, the balance of the State Bond Loan was $24.5 million.

 

Prior to closing the State Bond Loan, we had obtained interim financing from RMB which was paid off from the proceeds of the State Bond Loan. On December 19, 2013, we redrew $5.0 million from the RMB loan facility. We subsequently renegotiated the loan amount to $6.5 million together with an additional line of credit of $3.5 million. The RMB loan facility calls for payments of interest at 8.5% plus the three month LIBOR rate recalculated at the start of each calendar quarter (approximately 9.13% in total) plus eight equal quarterly principal payments which commenced June 30, 2014. On October 15, 2015, the loan was again amended to extend the maturity date of the $3.5 million line of credit to December 31, 2016 and spread the $3.5 million balance originally due March 31, 2016 over four quarterly payments commencing March 31, 2016 and concluding December 31, 2016, plus interest under the same terms as agreed to in September 2014. As of December 29, 2016 the loan was fully repaid.

 

On August 19, 2014, we filed a universal shelf registration statement on Form S-3 in order that we may offer and sell, from time to time, in one or more offerings, at prices and terms to be determined, up to $100 million of our Common Shares, warrants to purchase our Common Shares, our senior and subordinated debt securities, and rights to purchase our Common Shares and/or our senior and subordinated debt securities.  The registration statement became effective September 12, 2014. The 12,921,000 Common Shares offered in the February 2016 financing were sold for $0.50 per share raising $5.7 million (net of issue costs of $0.8 million) under the shelf registration statement. 

 

On May 27, 2016, we entered into an At Market Issuance Sales Agreement with MLV & Co. LLC and FBR Capital Markets & Co. under which we may, from time to time, issue and sell Common Shares at market prices on the NYSE MKT or other U.S. market through the distribution agents for aggregate sales proceeds of up to $10,000,000. During 2016, we sold 164,979 Common Shares under the sales agreement at an average price of $0.65 per share for gross proceeds of $108 thousand. After deducting transaction fees and commissions we received net proceeds of $105 thousand. After deducting all other costs associated with the initial completion of the agreement and filing the related prospectus supplement, we received $13 thousand.

 

Collections for the year from U3O8 sales totaled $27.3 million.

 

Operating activities generated $3.3 million of cash resources during the year ended December 31, 2016 as compared to $5.4 million in 2015. The change is due primarily to an increase in inventory of $0.8 million in 2016 combined with a decrease in inventory of $1.8 million in 2015. Offsetting the inventory value decrease was a reduction in depreciation and amortization of $1.4 million.

 

During 2016, the Company invested $0.3 million in equipment. The Lost Creek Project does not require significant capital expenditures and its sustaining capital expenditures have generally been less than $0.5 million per year.

 

During 2016, the Company used a net of $3.0 million for financing activities which was due to principal payments on debt of $8.7 million in debt repayments which was offset by net proceeds from the sale of common shares of $5.7 million.

 

Liquidity Outlook

 

As at March 2, 2017, our unrestricted cash position was $11.3 million.  We expect that any major capital projects will be funded by operating cash flow, cash on hand and additional financing as required. If these cash sources

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are not sufficient, certain capital projects could be delayed, or alternatively we may need to pursue additional debt or equity financing and there is no assurance that such financing will be available at all or on terms acceptable to us. We have no immediate plans to issue additional securities or obtain additional funding other than that which may be required due to the uneven nature of cash flows generated from operations; however, we may issue additional debt or equity securities at any time.

 

Outlook for 2017

 

In 2016, the average spot price per pound of U3O8, as reported by Ux Consulting Company, LLC and TradeTech, LLC, decreased approximately 47% to about $18.00 per pound in November. As a result, we deliberately reduced costs and slowed development activities at MU2, and focused on enhancing production efficiencies from our operating MU1 header houses.

 

Thus far in 2017, the average spot price per pound of U3O8 increased to about $26.50, but subsequently decreased to $23.00 as of February 27, indicating the fundamentals of market pricing have not changed sufficiently to warrant the accelerated development of MU2. In response, we will instead develop MU2 at a controlled rate, which will allow us to produce at a level that will satisfy a portion of our sales contracts.

 

In addition, we will further reduce costs by implementing a limited reduction in force, which will serve to further streamline our operations. The reduction in force affects personnel in all three company locations and is primarily focused on those departments not directly related to production. It is expected to reduce our labor costs by approximately $0.8 million per year. 

 

In 2017, we have 600,000 pounds of U3O8 under contract at an average price of approximately $51 per pound. We expect 2017 production from MU1 and MU2 to be between 250,000 and 300,000 pounds.  We have taken advantage of the low prices at the end of 2016 and in early 2017 to enter into purchase agreements for 410,000 pounds at an average cost of $22 per pound. We have already delivered a portion of these pounds and can readily deliver the remaining pounds from our current inventory and anticipated production.

 

Together, these actions will give the Company the additional flexibility necessary to quickly react to changing market conditions and accelerate the further development of MU2 when warranted.

 

We are not forecasting any spot sales at this time, although we may choose to do so if market conditions improve. We estimate the cost per pound sold from inventory will be higher in 2017 because we are producing at lower rates, which will lead to a higher cost per pound sold from production. This will continue to be the case until MU2 becomes operational and production rates increase again. We expect our average gross profit in 2017 to be between $13 and $15 million, which represents a gross profit margin of between 45% and 50%. On a cash basis, we expect our gross profit margin to be between 50% and 55%.

 

Operating costs in 2017 are expected to be higher than 2016 because of the controlled development of MU2, which is expected to result in the first three header houses of MU2 becoming operational in the second half of the year.  Other costs including capital expenditures and loan repayments will be similar to 2016, with the exception of the RMB loan facility, which was paid off in December 2016.

 

As at March 2, 2017, our unrestricted cash position was $11.3 million. Given our current cash resources, contracted sales positions and expected margins, we do not anticipate the need for additional funding in the near term unless it is advantageous to do so. 

 

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As discussed above, the Company has contractual sales commitments of 600,000 pounds during 2017, at an average price of approximately $51 per pound. We have established the schedule for those commitments and determined that an effective model for dealing with the current pricing environment is to maximize production from our fully operational first mine unit, and to begin production from the first three header houses of our second mine unit, which have already been partially developed.  This operating strategy for Lost Creek, coupled with cost effective purchases of uranium from the market, will allow us to control costs, minimize development expenditures and maximize cash flow.

 

Table of Contractual Obligations

 

The following table summarizes our contractual obligations as of December 31, 2016:

 

 

 

 

 

 

 

 

 

Payments due (by period) in thousands

 

 

Less than

 

3 to 5 years

More than

 

Total

1 year

1 to 3 years

years

5 years

 

 

 

 

 

 

Notes payable

$
24,514
$
4,623
$
10,078
$
9,813

$ -

Interest on notes payable

$
3,674
$
1,311
$
1,791
$
572

$ -

Operating leases

$
476
$
288
$
188

$ -

$ -

Environmental remediation

$
86
$
86

$ -

$ -

$ -

Asset retirement obligations

$
26,441

$  -

$
3,558
$
3,558
$
19,325

 

 

 

 

 

 

 

$
55,191
$
6,308
$
15,615
$
13,943
$
19,325

 

Outstanding Share Data

 

As of December 31, 2016 and 2015, the Company’s capital consisted of the following:

 

 

 

 

 

 

 

December 31, 2016

December 31, 2015

Change

 

  

 

 

Common shares

143,676,384
130,188,775
13,487,609

Warrants

5,844,567
8,224,112
(2,379,545)

RSUs

1,273,990
1,072,898
201,092

Stock options

9,748,934
9,974,407
(225,473)

 

 

 

 

Fully diluted shares outstanding

160,543,875
149,460,192
11,083,683

 

Off Balance Sheet Arrangements

 

We have not entered into any material off-balance sheet arrangements such as guaranteed contracts, contingent interests in assets transferred to unconsolidated entities, derivative instrument obligations, or with respect to any obligations under a variable interest entity arrangement.

 

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Financial Instruments and Other Instruments

 

The Company’s cash and cash equivalents are composed of:

 

 

 

 

 

 

As at

 

December 31, 2016

December 31, 2015

 

$ (thousands)

$ (thousands)

 

 

 

Cash on deposit at banks

580
1,202

Money market funds

972
241

 

 

 

 

1,552
1,443

 

Quarterly financial data (unaudited) (in thousands except for per share data)

 

 

 

 

 

 

 

2016

 

Quarter ended

 

Dec. 31

Sep. 30

Jun. 30

Mar. 31

 

 

 

 

 

Revenue

$
5,776
$
12,068
$
6,747
$
2,714

Net income (loss) for the period

$
104
$
1,802
$
(1,927)
$
(2,989)

 

 

 

 

 

Income (loss) per share – basic and diluted

$ -

$
0.01
$
(0.01)
$
(0.02)

 

 

 

 

 

 

 

 

2015

 

Quarter ended

 

Dec. 31

Sep. 30

Jun. 30

Mar. 31

 

 

 

 

 

Revenue

$
7,786
$
8,491
$
18,213
$
7,387

Net income (loss) for the period

$
591
$
(287)
$
1,025
$
(2,124)

 

 

 

 

 

Income (loss) per share – basic and diluted

$ -

$ -

$
0.01
$
(0.02)

 

Credit risk

 

Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents, deposits and restricted cash, which together totaled approximately $9.1 million at December 31, 2016.  These assets include Canadian dollar and U.S. dollar denominated certificates of deposit, money market accounts and demand deposits.  These instruments are maintained at financial institutions in Canada and the United States.  Of the amount held on deposit, approximately $0.6 million is covered by the Canada Deposit Insurance Corporation, the Securities Investor Protection Corporation or the United States Federal Deposit Insurance Corporation which leaves approximately $8.5 million at risk at December 31, 2016 should the financial institutions with which these amounts are invested be rendered insolvent.  We do not consider any of our financial assets to be impaired as of December 31, 2016.

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Liquidity risk

 

Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due.

 

As at December 31, 2016, our financial liabilities consisted of trade accounts payable and accrued trade and payroll liabilities of $1.3 million which are due within normal trade terms of generally 30 to 60 days, notes payable which will be payable over periods from three months to seven years and asset retirement obligations with estimated completion dates until 2033.

 

Item 7A.  Quantitative AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Market risk

 

Market risk is the risk to the Company of adverse financial impact due to changes in the fair value or future cash flows of financial instruments as a result of fluctuations in interest rates and foreign currency exchange rates.  As the US$ is now the functional currency of our U.S. operations, the currency risk has been significantly reduced.

 

Interest rate risk

 

Financial instruments that expose the Company to interest rate risk are its cash equivalents, deposits, restricted cash and debt financings. Our objectives for managing our cash and cash equivalents are to maintain sufficient funds on hand at all times to meet day to day requirements and to place any amounts which are considered in excess of day to day requirements on short-term deposit with the Company's financial institutions so that they earn interest.

 

Currency risk

 

We maintain a balance of less than $0.1 million in foreign currency resulting in a low currency risk.

 

Commodity Price Risk

 

The Company is subject to market risk related to the market price of uranium. We have multiple uranium supply contracts with pricing fixed or based on inflation factors applied to a fixed base.  Additional future sales would be impacted by both spot and long-term uranium price fluctuations. Historically, uranium prices have been subject to fluctuation, and the price of uranium has been and will continue to be affected by numerous factors beyond our control, including the demand for nuclear power, political and economic conditions, and governmental legislation in uranium producing and consuming countries and production levels and costs of production of other producing companies. The spot market price for uranium has demonstrated a large range since January 2001. Prices have risen from $7.10 per pound at January 2001 to a high of $136.00 per pound as of June 2007. The spot market price was $23.00 per pound as of February 27, 2017.

 

 

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Transactions with Related Parties

 

Jeff Klenda, CEO, purchased 1,000,000 Common Shares under the bought-deal financing in February 2016 for gross proceeds of $500,000 at the same price as other investors.  There were no other reportable transactions with related parties in 2016.

 

During the fiscal year ended December 31, 2015, we did not participate in any reportable transactions with related parties.

 

Proposed Transactions

 

As is typical of the mineral exploration and development industry, we will consider and review potential merger, acquisition, investment and venture transactions and opportunities that could enhance shareholder value. 

 

Recent Accounting Pronouncements Not Yet Adopted

 

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”.  The amendments in ASU 2014-09 affect any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance, and creates a Topic 606 Revenue from Contracts with Customers.  The core principle of the guidance is that an entity should recognize revenue to depict the transfer of the promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The amendments are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  Early application is not permitted.  We have reviewed our contracts as well as our procedures and do not anticipate any changes in the manner or timing with which we reflect our revenues.

 

In July 2015, the FASB issued Accounting Standards Update No. 2015-11,  Inventory (Topic 330): Simplifying the Measurement of Inventory.  ASU 2015-11 requires that inventory within the scope of this ASU be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments in this ASU do not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first-out (FIFO) or average cost. For all entities, the guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted. Therefore, the amendments in ASU 2015-11 will become required for us as of the beginning of our 2017 fiscal year. This is consistent with our current policies and is not expected to have a material impact upon our financial condition or results of operations.

 

In January 2016, the FASB issued ASU 2016-1, Recognition and Measurement of Financial Assets and Financial Liabilities (Topic 825). The amendments in this ASU supersede the guidance to classify equity securities with readily determinable fair values into different categories (that is, trading or available-for-sale) and require equity securities (including other ownership interests, such as partnerships, unincorporated joint ventures, and limited liability companies) to be measured at fair value with changes in the fair value recognized through net income. The amendments allow equity investments that do not have readily determinable fair values to be remeasured at fair value either upon the occurrence of an observable price change or upon identification of an impairment. The amendments also require enhanced disclosures about those investments. The

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amendments improve financial reporting by providing relevant information about an entity’s equity investments and reducing the number of items that are recognized in other comprehensive income. This guidance is effective for annual reporting beginning after December 15, 2017, including interim periods within the year of adoption, and calls for prospective application, with early application permitted. Accordingly, the standard is effective for us beginning in the first quarter of fiscal 2019. The adoption of this guidance is not expected to have a material impact on our consolidated financial statements.

 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize all leases, including operating leases, unless the lease is a short-term lease. ASU 2016-02 also requires additional disclosures regarding leasing arrangements. ASU 2016-02 is effective for interim periods and fiscal years beginning after December 15, 2018, and early application is permitted.  At this time, the only leases we hold are for equipment, office space in one location and a limited number of leases on selected mineral properties.  We do not anticipate the additional disclosures to reflect those leases will have an impact on our statement of financial position as the total future lease payments are not material.

 

In March 2016, the FASB issued ASU No. 2016-09Compensation-Stock Compensation- Improvements to Employee Share-Based Payment Accounting (Topic 718), which involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  Under the new standard, income tax benefits and deficiencies are to be recognized as income tax expense or benefit in the income statement and the tax effects of exercised or vested awards should be treated as discrete items in the reporting period in which they occur.  An entity should also recognize excess tax benefits regardless of whether the benefit reduces taxes payable in the current period.  Excess tax benefits should be classified along with other income tax cash flows as an operating activity.  In regard to forfeitures, the entity may make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. This ASU is effective for fiscal years beginning after December 15, 2016 including interim periods within that reporting period, however early adoption is permitted.  We are currently evaluating the guidance to determine the Company's adoption method and the effect it will have on the Company's Consolidated Financial Statements.

 

In November 2016, the FASB issued ASU No. 2016-18Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Task Force (Topic 230), which addresses the presentation of restricted cash in the statement of cash flows.  Under the new standard, restricted cash will be presented with cash and cash equivalents in the statement of cash flows instead of being reflect as non-cash investing or financing activities.  A reconciliation of the make-up of the end ending cash, cash equivalent and restricted cash balance will be required for entities who reflect restricted cash as separate items on the statement of financial position.  In addition, a description of the restrictions on the cash will be required.  This ASU is effective for fiscal years beginning after December 15, 2017 including interim periods within that reporting period, however early adoption is permitted.  We are currently evaluating the guidance to determine the Company's adoption method and the effect it will have on the Company's Consolidated Financial Statements.

 

Critical Accounting Policies and Estimates

 

We have established the existence of mineral resources at the Lost Creek Project, but because of the unique nature of in situ recovery mines, we have not established, and have no plans to establish the existence of proven and probable reserves at this project.

 

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Mineral Properties

 

Acquisition costs of mineral properties are capitalized. When production is attained at a property, these costs will be amortized over a period of estimated benefit.

 

As of December 31, 2016, the current and long term price of uranium was $20.25 and $30.00, respectively.  This compares to prices of $34.23 and $44.00 as of December 31, 2015. Senior management updates production, revenue and cash projections on a regular basis, in some cases weekly, but at least monthly. The Company reviews the impairment indicators outlined in GAAP guidance. The sole indication of possible impairment was the decline in industry-wide reported sales price. While this has no immediate effect on the Company since it has sales contracts until 2021, a cash flow analysis for each of Lost Creek and Shirley Basin was performed. The mine life used was consistent with that reported in the respective NI 43‑101 Preliminary Economic Assessment for each property. Cash flows were calculated on a sales price of $30 per pound which was the long-term quoted price in related industry periodicals as of December 31, 2016.  Based on these undiscounted cash flow models, no impairments were indicated for any of the respective properties.

 

For other properties which have reported mineral resources supported by NI 43-101 Technical Reports, we applied the estimated market pricing to the mineral resource estimates as well as realization percentages which were taken from a previous valuation completed by a third party with respect to the Lost Creek Project in conjunction with obtaining our Wyoming bond.

 

Our remaining properties, which have no established mineral resource, continue to be carried at their acquisition cost.

 

Development costs including, but not limited to, production wells, header houses, piping and power will be expensed as incurred as we have no proven and probable reserves.

 

Exploration, evaluation and development costs

 

Exploration and evaluation expenses consist of labor, annual exploration lease and maintenance fees and associated costs of the exploration geology department as well as land holding and exploration costs including drilling and analysis on properties which have not reached the permitting or operations stage. Development expense relates to the Company’s Lost Creek, LC East and Shirley Basin projects, which are more advanced in terms of permitting and preliminary economic assessments.  Development expenses include all costs associated with exploring, delineating and permitting new or expanded mine units, the costs associated with the construction and development of permitted mine units including wells, pumps, piping, header houses, roads and other infrastructure related to the preparation of a mine unit to begin extraction operations as well as the cost of drilling and completing disposal wells.

 

Capital assets

 

Property, plant and equipment assets, including machinery, processing equipment, enclosures, vehicles and expenditures that extend the life of such assets, are recorded at cost including acquisition and installation costs.  The enclosure costs include both the building housing and the processing equipment necessary for the extraction of uranium from impregnated water pumped in from the wellfield to the packaging of uranium yellowcake for delivery into sales.  These enclosure costs are combined as the equipment and related installation associated with the equipment is an integral part of the structure itself. The costs of self-constructed assets include direct construction costs, direct overhead and allocated interest during the construction phase. Depreciation is calculated using a declining balance method for most assets with the exception of the plant enclosure and related

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equipment. Depreciation on the plant enclosure and related equipment is calculated on a straight-line basis. Estimated lives for depreciation purposes range from three years for computer equipment and software to 20 years for the plant enclosure and the name plate life of the related equipment.

 

Depreciation

 

The depreciable life of the Lost Creek plant, equipment and enclosure was determined to be the nameplate life of the equipment housed in the processing plant as plans exist to continue to process materials from other sources such as Shirley Basin beyond the estimated production at the Lost Creek Project.

 

Inventory and Cost of Sales

 

Our inventories are measured at the lower of cost and net realizable value based on projected revenues from the sale of that product.  We are allocating all costs of operations of the Lost Creek facility to the inventory valuation at various stages of production with the exception of wellfield and disposal well costs which are treated as development expenses when incurred. Depreciation of facility enclosures, equipment and asset retirement obligations as well as amortization of the acquisition cost of the related property is also included in the inventory valuation.  We do not allocate any administrative or other overhead to the cost of the product.

 

Because of the nature of in situ operations, it is not economically feasible to accurately measure the amount of in-process inventory at any given time.  We use a combination of calculating estimated uranium captured per sampling applied to total water processing flow to determine the estimated pounds captured.

 

Share-Based Compensation

 

We are required to initially record all equity instruments including warrants, restricted share units and stock options at fair value in the financial statements.

 

Management utilizes the Black-Scholes model to calculate the fair value of the warrants and stock options at the time they are issued.  Use of the Black-Scholes model requires management to make estimates regarding the expected volatility of the Company’s stock over the future life of the equity instrument, the estimate of the expected life of the equity instrument and the number of options that are expected to be forfeited.  Determination of these estimates requires significant judgment and requires management to formulate estimates of future events based on a limited history of actual results.

 

Income taxes

 

The Company accounts for income taxes under the asset and liability method which requires the recognition of future income tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and tax bases of assets and liabilities. The Company provides a valuation allowance on future tax assets unless it is more likely than not that such assets will be realized.

 

In 2013, we acquired Pathfinder as a corporate entity.  In terms for the acquisition, there were no net operating losses or other tax attributes that carried forward to the Company with the acquisition.  In addition, the assets acquired had no tax basis within the corporation.  The seller also did not make the Sec. 338(h)(10) election to allow us to push the purchase price down to the asset level for tax purposes.  As a result, it was determined that the acquisition should not be treated as a business combination since Pathfinder was not a going concern.  A tax of $3.3 million was calculated as a potential liability of the acquisition and was recorded as a deferred tax

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liability and an increase in basis.  For accounting/reporting purposes, this value was added to the accounting basis in the assets acquired. 

 

In early 2015, we completed and filed the Shirley Basin PEA based on drilling data purchased as a part of the acquisition combined with data gathered during the exploration / confirmation program undertaken in 2014.  After filing the Shirley Basin PEA, we continued to do baseline and confirmation work at Shirley Basin and in late 2015 we submitted a permit application to the state of Wyoming to begin construction and operations at the project.  Based on the filing of those permits, we anticipate that we will be in a position to commence construction of a plant facility and the related wellfields within several years.  Once operations commence, the cost of the property will be amortized over the anticipated productive life of the property for accounting / reporting purposes.  At this point, the asset now has an identifiable life and the associated DTL is available to offset the DTA recorded before the application of the valuation allowance.  We therefore applied a portion of the valuation allowance to the DTL arising from the Pathfinder acquisition.

 

Item 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

See “Index to Consolidated Financial Statements” following the signature page of this Form 10-K.

 

Item 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

None.

 

Item 9A. Controls and Procedures

 

(a)

Evaluation of Disclosure Controls and Procedures

 

As of the fiscal year ended December 31, 2016, under the supervision of the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of its disclosure controls and procedures, as such term is defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on this evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective to ensure that information the Company is required to disclose in reports that are filed or submitted under the Exchange Act: (1) is recorded, processed and summarized effectively and reported within the time periods specified in SEC rules and forms, and (2) is accumulated and communicated to Company management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s disclosure controls and procedures include components of internal control over financial reporting. No matter how well designed and operated, internal controls over financial reporting can provide only reasonable, but not absolute, assurance that the control system's objectives will be met.

 

(b)Management’s Report on Internal Control over Financial Reporting

 

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, the Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f).  The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with US GAAP.

 

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All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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 the degree of compliance with the policies or procedures may deteriorate.

 

As of December 31, 2016, management conducted an assessment of the effectiveness of the Company's internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its assessment using those criteria, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2016. The effectiveness of the Company’s internal control over financial reporting at December 31, 2016, has been audited by PricewaterhouseCoopers LLP, as stated in their report.

 

(c)Attestation Report of Registered Public Accounting Firm

 

PricewaterhouseCoopers LLP’s attestation report on our internal control over financial reporting is included as part of Item 8. Financial Statements and Supplementary Data herein.

 
(d)Changes in Internal Controls over Financial Reporting

No changes in our internal control over financial reporting occurred during the year ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information

 

None.

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PART III

 

Item 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2017 Annual Meeting of Shareholders and is incorporated by reference in this report.

 

Code of Ethics

 

We have adopted a Code of Ethics (“Code”) which applies to all employees, officers and directors. The full text of the Code is available on our website at http://www.ur-energy.com/corporate-governance/. We will post any amendments to, or waivers from, the Code on our corporate website or by filing a Current Report on Form 8‑K.

 

Item 11.  EXECUTIVE COMPENSATION

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2017 Annual Meeting of Shareholders and is incorporated by reference in this report.

 

Item 12. SECURITY OWNERSHIP OF Certain BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2017 Annual Meeting of Shareholders and is incorporated by reference in this report.

 

Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2017 Annual Meeting of Shareholders and is incorporated by reference in this report.

 

Item 14.  PRINCIPAL ACCOUNTing FEES AND SERVICES

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2017 Annual Meeting of Shareholders and is incorporated by reference in this report.

 

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PART IV

 

Item 15.  Exhibits, Financial statement schedules

 

Financial Statements and Financial Statement Schedules

 

See “Index to Consolidated financial statements” on page F-1.

 

 

 

 

 

 

 

 

 

 

 

 

   

   

   

   

Incorporated by Reference

   

   

Exhibit Number

   

Exhibit Description

   

Form

 

Date of Report

 

Exhibit

   

Filed Herewith

3.1

   

Articles of Continuance and Articles of Amendment

   

S-3

 

1/10/2015

 

3.1

   

 

   

   

   

   

   

 

   

 

   

   

   

3.2

   

Amended By-Law No. 1

   

S-3

 

1/10/2015

 

3.2

   

 

   

   

   

   

   

 

   

 

   

   

   

3.3

 

By-Law No. 2 (Advance Notice)

 

8-K

 

2/25/2017

 

3.1

 

 

 

 

 

 

 

 

 

 

 

 

 

10.1

   

Financing Agreement and Mortgage (State of Wyoming Industrial Revenue Bond Loan)

   

6-K

 

10/29/2013

 

99.1

   

   

 

 

 

 

 

 

 

 

 

 

 

10.2

 

Second Amendment and Restatement Agreement – Facility Agreement (RMB Australia Holdings Ltd)

 

8-K

 

03/19/2015

 

10.1

 

 

 

 

 

 

 

 

 

 

 

 

 

10.3

 

Share Purchase Agreement and Registration Rights Agreement (Private Placement)

 

6-K

 

12/19/2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10.4

 

Amended Share Purchase Agreement (Pathfinder Mines Corporation)

 

6-K

  

12/23/2013

 

10.1

 

 

 

 

 

 

 

 

 

 

 

 

 

10.5

 

Employment Agreement with Jeffrey T. Klenda, as amended

 

10-K

 

3/3/2014

 

10.7

 

 

 

 

 

 

 

 

 

 

 

 

 

10.6

 

Employment Agreement with Wayne W. Heili, as amended

 

10-K

 

3/3/2014

 

10.8

 

 

 

 

 

 

 

 

 

 

 

 

 

10.7

 

Employment Agreement with Roger L. Smith, as amended

 

10-K

 

3/3/2014

 

10.9

 

 

 

 

 

 

 

 

 

 

 

 

 

10.8

 

Employment Agreement with Steven M. Hatten, as amended

 

10-K

 

3/3/2014

 

10.10

 

 

 

 

 

 

 

 

 

 

 

 

 

10.9

 

Employment Agreement with John W. Cash, as amended

 

10-K

 

3/3/2014

 

10.11

 

 

 

 

 

 

 

 

 

 

 

 

 

10.13

 

Employment Agreement with Penne A. Goplerud, as amended

 

10-K

 

3/3/2014

 

10.12

 

 

 

 

 

 

 

 

 

 

 

 

 

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10.10

 

Employment Agreement with James A. Bonner

 

10-K

 

3/2/2015

 

10.14

 

 

 

 

 

 

 

 

 

 

 

 

 

10.11

 

Ur-Energy Inc. Amended and Restated Stock Option Plan

 

S-8

 

5/14/2013

 

4.1

 

 

 

 

 

 

 

 

 

 

 

 

 

10.12

 

Amended Restricted Share Unit Plan

 

8-K

 

3/27/2016

 

4.2

 

 

 

 

 

 

 

 

 

 

 

 

 

10.13

 

At Market Issuance Sales Agreement

 

8-K

 

5/27/16

 

1.1

 

 

 

 

 

 

 

 

 

 

 

 

 

14.1

 

Code of Ethics for CEO, CFO and Senior Financial Officers

 

8-K

 

2/11/2014

 

14.1

 

 

 

 

 

 

 

 

 

 

 

 

 

21.1

   

Subsidiaries of the Registrant

   

10-K

 

3/3/2014

 

 

 

 

   

   

   

   

   

 

   

 

   

   

   

23.1

   

Consent of PricewaterhouseCoopers LLP

   

   

 

   

 

   

   

X

 

 

 

 

 

 

 

 

 

 

 

23.2

 

Consent of TREC, Inc.

 

 

 

 

 

 

 

X

   

   

   

   

   

 

   

 

   

   

   

23.3

 

Consent of WWC Engineering

 

 

 

 

 

 

 

X

 

 

 

 

 

 

 

 

 

 

 

31.1

   

Certification of CEO Pursuant to Exchange Act Rules 13a-14 and 15d-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

   

   

 

   

 

   

   

X

   

   

   

   

   

 

   

 

   

   

   

31.2

   

Certification of CFO Pursuant to Exchange Act Rules 13a-14 and 15d-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

   

   

 

   

 

   

   

X

   

   

   

   

   

 

   

 

   

   

   

32.1

   

Certification of CEO Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

   

   

 

   

 

   

   

X

   

   

   

   

   

 

   

 

   

   

   

32.2

   

Certification of CFO Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

   

   

 

   

 

   

   

X

 

 

 

 

 

 

 

 

 

 

 

101.INS

 

XBRL Instance Document

 

 

 

 

 

 

 

X

 

 

 

 

 

 

 

 

 

 

 

101.SCH

 

XBRL Schema Document

 

 

 

 

 

 

 

X

 

 

 

 

 

 

 

 

 

 

 

101.CAL

 

XBRL Calculation Linkbase Document

 

 

 

 

 

 

 

X

 

 

 

 

 

 

 

 

 

 

 

101.DEF

 

XBRL Definition Linkbase Document

 

 

 

 

 

 

 

X

 

 

 

 

 

 

 

 

 

 

 

101.LAB

 

XBRL Labels Linkbase Document

 

 

 

 

 

 

 

X

 

 

 

 

 

 

 

 

 

 

 

101.PRE

 

XBRL Presentation Linkbase Document

 

 

 

 

 

 

 

X

 

 

 

 

 

 

 

 

 

 

 

99.1

   

Location maps (1)

   

10-K

 

3/3/2014

 

 

 

 

73


 

Table of Contents

   

   

   

   

   

 

   

 

   

   

   

 

(1)

Filed herewith under Items 1 and 2. Business and Properties.

 

 

ITEM 16.  FORM 10-K SUMMARY

 

None.

74


 

Table of Contents

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.

 

 

 

 

 

 

UR-ENERGY INC.

 

 

 

Date: March 3, 2017

By:  

/s/ Jeffrey T. Klenda

 

 

Jeffrey T. Klenda

 

 

Chief Executive Officer

 

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

 

 

 

 

Date: March 3, 2017

By:

/s/ Jeffrey T. Klenda

 

 

Jeffrey T. Klenda

 

 

Chief Executive Officer (Principal Executive Officer)

 

 

 

Date: March 3, 2017

By:

/s/Roger L. Smith

 

 

Roger L. Smith

 

 

Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

 

 

 

Date: March 2, 2017

By:

/s/ W. William Boberg

 

 

W. William Boberg

 

 

Director

 

 

 

Date: March 2, 2017

By:

/s/ James M. Franklin

 

 

James M. Franklin

 

 

Director

 

 

 

Date: March 2, 2017

By:

/s/ Paul Macdonell

 

 

Paul Macdonell

 

 

Director

 

 

 

Date: March 2, 2017

By:

/s/ Thomas Parker

 

 

Thomas Parker

 

 

Director

 

 

 

Date: March 2, 2017

By:

/s/ Gary C. Huber

 

 

Gary C. Huber

 

 

Director

 

 

 

 

 

75


 

Table of Contents

Ur-Energy Inc.

 

Headquartered in Littleton, Colorado

 

Consolidated Financial Statements

 

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

 

76


 

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Shareholders of Ur-Energy Inc.

We have audited the accompanying consolidated balance sheets of Ur-Energy Inc. (Ur-Energy or the Company) as of December 31, 2016 and December 31, 2015 and the related consolidated statements of operations and comprehensive loss, cash flows and shareholder’s equity for each of the years in the three-year period ended December 31, 2016. We also have audited Ur-Energy’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our integrated audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall consolidated financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect 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 the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ur-Energy as of December 31, 2016 and 2015 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, Ur-Energy maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

Vancouver, British Columbia

March 3, 2017

77


 

Table of Contents

Ur-Energy Inc.

Consolidated Balance Sheets

(expressed in thousands of U.S. dollars)

 

 

 

 

 

 

December 31,

 

December 31,

 

2016

 

2015

Assets

 

 

 

Current assets

 

 

 

Cash and cash equivalents (note 4)

1,552

 

1,443

Accounts receivable

16

 

9

Inventory (note 5)

4,109

 

3,345

Prepaid expenses

829

 

916

 

6,506

 

5,713

Restricted cash (note 6)

7,557

 

7,557

Mineral properties (note 7)

47,029

 

50,610

Capital assets (note 8)

28,848

 

30,788

Equity investment (note 9)

 -

 

1,089

 

89,940

 

95,757

Liabilities and shareholders' equity

 

 

 

Current liabilities

 

 

 

Accounts payable and accrued liabilities (note 10)

3,625

 

4,567

Current portion of notes payable (note 11)

4,502

 

8,527

Accrued federal income tax (note 12)

 -

 

43

Environmental remediation accrual

85

 

86

 

8,212

 

13,223

Notes payable (note 11)

19,435

 

23,937

Asset retirement obligations (note 13)

26,061

 

26,061

Other liabilities - warrants

 -

 

35

 

53,708

 

63,256

Shareholders' equity (note 14)

 

 

 

Share Capital

 

 

 

Class A preferred shares, without par value, unlimited shares authorized; no shares issued and outstanding

 -

 

 -

Common shares, without par value, unlimited shares authorized; shares issued and outstanding: 143,676,384 at December 31, 2016 and 130,188,775 at December 31, 2015

174,902

 

168,911

Warrants

4,109

 

4,175

Contributed surplus

15,201

 

14,632

Accumulated other comprehensive income

3,604

 

3,357

Deficit

(161,584)

 

(158,574)

 

36,232

 

32,501

 

89,940

 

95,757

 

The accompanying notes are an integral part of these consolidated financial statements.

 

Approved by the Board of Directors

 

 

 

 

/s/ Jeffrey T. Klenda, Chairman

 

/s/ Thomas H. Parker, Director

 

78


 

Table of Contents

Ur-Energy Inc.

Consolidated Statements of Operations and Comprehensive Loss

(expressed in thousands of U.S. dollars except for share data)

 

 

 

 

 

 

 

 

 

Year ended December 31,

 

2016

 

2015

 

2014

 

 

 

 

 

 

Sales (note 15)

27,305

 

41,877

 

29,349

 

 

 

 

 

 

Cost of sales

(15,848)

 

(29,292)

 

(17,858)

 

 

 

 

 

 

Gross profit

11,457

 

12,585

 

11,491

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

Exploration and evaluation

(2,964)

 

(2,853)

 

(3,277)

Development

(2,886)

 

(5,358)

 

(7,672)

General and administrative

(4,740)

 

(5,715)

 

(6,541)

Accretion of asset retirement obligations (note 13)

(534)

 

(515)

 

(497)

Write-off of mineral properties (note 7)

(62)

 

 -

 

(483)

 

 

 

 

 

 

Income (loss) from operations

271

 

(1,856)

 

(6,979)

 

 

 

 

 

 

Interest expense (net)

(1,977)

 

(2,557)

 

(2,699)

Warrant mark to market adjustment

36

 

307

 

946

Loss on equity investment (note 9)

(5)

 

(8)

 

(5)

Write-off of equity investments (note 9)

(1,089)

 

 -

 

 -

Foreign exchange gain (loss)

(278)

 

(1)

 

(12)

Other income (loss)

15

 

5

 

 -

 

 

 

 

 

 

Loss before income taxes

(3,027)

 

(4,110)

 

(8,749)

 

 

 

 

 

 

Income tax recovery (net) (note 12)

17

 

3,315

 

 -

 

 

 

 

 

 

Net loss for the year

(3,010)

 

(795)

 

(8,749)

 

 

 

 

 

 

Loss per common share

 

 

 

 

 

Basic and diluted

(0.02)

 

(0.01)

 

(0.07)

 

 

 

 

 

 

Weighted average number of common shares outstanding

 

 

 

 

 

Basic and diluted

141,999,537

 

130,056,932

 

128,781,215

 

 

 

 

 

 

COMPREHENSIVE INCOME (LOSS)

 

 

 

 

 

Net loss for the year

(3,010)

 

(795)

 

(8,749)

Other Comprehensive loss, net of tax

 

 

 

 

 

Translation adjustment on foreign operations

247

 

20

 

39

Comprehensive loss for the year

(2,763)

 

(775)

 

(8,710)

 

The accompanying notes are an integral part of these consolidated financial statements.

79


 

Table of Contents

Ur-Energy Inc.

Consolidated Statements of Shareholders’ Equity

(expressed in thousands of U.S. dollars except for share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

Capital Stock

 

 

 

Contributed

 

Comprehensive

 

 

 

Shareholders'

 

Shares

 

Amount

 

Warrants

 

Surplus

 

Income

 

Deficit

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

#

 

$

 

$

 

$

 

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2013

127,559,743

 

165,974

 

4,175

 

14,247

 

3,298

 

(149,030)

 

38,664

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercise of stock options

1,623,139

 

2,052

 

 -

 

(705)

 

 -

 

 -

 

1,347

Common shares issued for cash, net

 

 

 

 

 

 

 

 

 

 

 

 

 

  of issue costs - additional costs

 -

 

(50)

 

 -

 

 -

 

 -

 

 -

 

(50)

Redemption of vested RSUs

182,194

 

142

 

 -

 

(225)

 

 -

 

 -

 

(83)

Other capital contributions

 -

 

 -

 

 -

 

5

 

 -

 

 -

 

5

Non-cash stock compensation

 -

 

 -

 

 -

 

928

 

 -

 

 -

 

928

Net loss and comprehensive income

 -

 

 -

 

 -

 

 -

 

39

 

(8,749)

 

(8,710)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2014

129,365,076

 

168,118

 

4,175

 

14,250

 

3,337

 

(157,779)

 

32,101

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercise of stock options

608,531

 

626

 

 -

 

(216)

 

 -

 

 -

 

410

Redemption of vested RSUs

215,168

 

167

 

 -

 

(295)

 

 -

 

 -

 

(128)

Non-cash stock compensation

 -

 

 -

 

 -

 

893

 

 -

 

 -

 

893

Net loss and comprehensive income

 -

 

 -

 

 -

 

 -

 

20

 

(795)

 

(775)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2015

130,188,775

 

168,911

 

4,175

 

14,632

 

3,357

 

(158,574)

 

32,501

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercise of stock options

16,620

 

13

 

 -

 

(4)

 

 -

 

 -

 

9

Common shares issued for cash, net

 

 

 

 

 

 

 

 

 

 

 

 

 

  of $884 of issue costs

13,085,979

 

5,684

 

 -

 

 -

 

 -

 

 -

 

5,684

Redemption of vested RSUs

385,010

 

294

 

 -

 

(350)

 

 -

 

 -

 

(56)

Expiry of warrants

 -

 

 -

 

(66)

 

66

 

 -

 

 -

 

 -

Non-cash stock compensation

 -

 

 -

 

 -

 

857

 

 -

 

 -

 

857

Net loss and comprehensive income

 -

 

 -

 

 -

 

 -

 

247

 

(3,010)

 

(2,763)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2016

143,676,384

 

174,902

 

4,109

 

15,201

 

3,604

 

(161,584)

 

36,232

 

The accompanying notes are an integral part of these consolidated financial statements

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Ur-Energy Inc.

Consolidated Statements of Cash Flow

(expressed in thousands of U.S. dollars)

 

 

 

 

 

 

 

 

 

Year ended December 31,

 

2016

 

2015

 

2014

Cash provided by (used in)

 

 

 

 

 

Operating activities

 

 

 

 

 

Net loss for the year

(3,010)

 

(795)

 

(8,749)

Items not affecting cash:

 

 

 

 

 

Stock based expense

857

 

893

 

928

Depreciation and amortization

5,144

 

6,504

 

7,643

Accretion of asset retirement obligations

534

 

515

 

497

Amortization of deferred loan costs

152

 

177

 

 -

Write off of equity investments

1,089

 

 -

 

 -

Write-off of mineral properties

62

 

 -

 

483

Warrants mark to market gain

(36)

 

(307)

 

(946)

Gain on disposition of assets

(14)

 

(5)

 

 -

Loss on foreign exchange

280

 

 -

 

 

Other loss

4

 

9

 

4

Income tax recovery

(17)

 

(3,345)

 

 -

RSUs redeemed to pay withholding

(56)

 

(142)

 

(67)

Proceeds from assignment of sales contract

 -

 

 -

 

(2,508)

Change in non-cash working capital items:

 

 

 

 

 

Accounts receivable

(7)

 

19

 

5,772

Inventory

(765)

 

1,823

 

(3,115)

Prepaid expenses

(111)

 

125

 

259

Accounts payable and accrued liabilities

(803)

 

(101)

 

1,736

Accrued income taxes

30

 

 -

 

 -

 

3,333

 

5,370

 

1,937

Investing activities

 

 

 

 

 

Mineral property costs

 -

 

1

 

(65)

Increase in restricted cash

 -

 

 -

 

(2,500)

Funding of equity investment

(5)

 

(8)

 

(7)

Proceeds from sale of property and equipment

91

 

26

 

 -

Purchase of capital assets

(296)

 

(79)

 

(436)

 

(210)

 

(60)

 

(3,008)

Financing activities

 

 

 

 

 

Issuance of common shares and warrants for cash

6,568

 

 -

 

 -

Share issue costs

(884)

 

 -

 

(50)

Proceeds from exercise of stock options

9

 

410

 

1,347

Proceeds from debt financing

 -

 

 -

 

5,000

Cost of debt financing

 -

 

 -

 

(135)

Repayment of debt

(8,679)

 

(7,374)

 

(3,585)

 

(2,986)

 

(6,964)

 

2,577

Effects of foreign exchange rate changes on cash

(28)

 

(7)

 

(29)

Net change in cash and cash equivalents

109

 

(1,661)

 

1,477

Beginning cash and cash equivalents

1,443

 

3,104

 

1,627

   Ending cash and cash equivalents

1,552

 

1,443

 

3,104

Total Interest paid

1,827

 

2,385

 

2,526

Total taxes paid

29

 

 -

 

 -

 

The accompanying notes are an integral part of these consolidated financial statements

 

 

 

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Table of Contents

Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

1.Nature of Operations

 

Ur-Energy Inc. (the “Company”) was incorporated on March 22, 2004 under the laws of the Province of Ontario. The Company continued under the Canada Business Corporations Act on August 8, 2006. The Company is an exploration stage mining company, as defined by United States Securities and Exchange Commission (“SEC”) Industry Guide 7, headquartered in Littleton, Colorado.  The Company is engaged in uranium mining and recovery operations, with activities including the acquisition, exploration, development and production of uranium mineral resources located primarily in Wyoming. As of August 2013, the Company commenced uranium production at its Lost Creek Project in Wyoming.

 

Due to the nature of the uranium mining methods used by the Company on the Lost Creek Property, and the definition of “mineral reserves” under National Instrument 43-101 (“NI 43-101”), which uses the Canadian Institute of Mining, Metallurgy and Petroleum (“CIM”) Definition Standards, the Company has not determined whether the properties contain mineral reserves. However, the Company’s January 19, 2016 NI 43-101 Technical Report on Lost Creek, “Preliminary Economic Assessment of the Lost Creek Property, Sweetwater County, Wyoming,” as amended in non-substantive ways, February 8, 2016 (“Lost Creek PEA”) outlines the potential viability of the Lost Creek Property.   The recoverability of amounts recorded for mineral properties is dependent upon the discovery of economic resources, the ability of the Company to obtain the necessary financing to develop the properties and upon attaining future profitable production from the properties or sufficient proceeds from disposition of the properties.

 

2.Liquidity Risk

 

Our operations are based on a small number of large sales.  As a result, our cash flow and therefore our current assets and working capital may vary widely during the year based on the timing of those sales.  Virtually all of our sales are under contracts which specify delivery dates, delivery quantities, sales prices and payment dates.  The only exceptions are spot sales which we are currently only making when advantageous. As a result, we are able to perform cash management functions over the course of an entire year and are less reliant on current commodity prices and market conditions. We monitor our cash projections on a weekly basis and have used various techniques to manage our cash flows including the assignment of deliveries, as we did in 2016, negotiating changes in delivery dates, purchasing inventory at favorable prices and raising capital.

 

In addition, most of our current assets except for prepaid expenses are immediately realizable, if necessary, while our currently liabilities include a substantial portion that is not due for a minimum of three months to over a year which, given the existence of our contracts and set prices, allow us to plan for those payments well in advance and address shortfalls, if any, well in advance.

 

While our current position as of December 31, 2016 reflects negative working capital, our projected sales for the first quarter of 2017 are sufficient to cover any perceived shortfall as well as any required debt service payments.

 

It is possible that additional funding might be sought.  Although the Company has been successful in raising debt and equity financing in the past, there can be no guarantee that such funding will be available in the future.

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

3.Summary of Significant Accounting Policies

 

Basis of presentation

 

These financial statements have been prepared by management in accordance with United States generally accepted accounting principles (“US GAAP”) and include all of the assets, liabilities and expenses of the Company and its wholly-owned subsidiaries Ur-Energy USA Inc.; NFU Wyoming, LLC; Lost Creek ISR, LLC; NFUR Bootheel, LLC; Hauber Project LLC; NFUR Hauber, LLC; and Pathfinder Mines Corporation. All inter-company balances and transactions have been eliminated upon consolidation. Ur-Energy Inc. and its wholly-owned subsidiaries are collectively referred to herein as the “Company.”

 

 Exploration Stage

The Company has established the existence of uranium resources for certain uranium projects, including the Lost Creek Property. The Company has not established proven or probable reserves, as defined by the SEC under Industry Guide 7, through the completion of a final or “bankable” feasibility study for any of its uranium projects, including the Lost Creek Property. Furthermore, the Company has no plans to establish proven or probable reserves for any of its uranium projects for which the Company plans on utilizing in-situ recovery (“ISR”) mining, such as the Lost Creek Property or the Shirley Basin Project. As a result, and despite the fact that the Company commenced recovery of uranium at the Lost Creek Project in August 2013, the Company remains in the Exploration Stage as defined under Industry Guide 7, and will continue to remain in the Exploration Stage until such time proven or probable mineral reserves have been established.

Since the Company commenced recovery of uranium at the Lost Creek Project without having established proven and probable reserves, any uranium resources established or extracted from the Lost Creek Project should not be in any way associated with having established, or production from, proven or probable mineral reserves. Accordingly, information concerning mineral deposits set forth herein may not be comparable to information made public by companies that have reserves in accordance with United States standards.

Use of estimates

 

The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates management makes in the preparation of these consolidated financial statements relate to potential impairment in the carrying value of the Company’s long-lived assets due to declining uranium prices or other internal or external factors, the fair value of stock-based compensation using the factors associated with the Black-Scholes calculations, estimation of the amount of recoverable uranium included in the in-process inventory, estimation of factors surrounding asset retirement obligations such as interest rates, discount rates and inflation rates, total cost and the time until the asset retirement commences and the offset of future income taxes through deferred tax assets. Actual results could differ from those estimates.

 

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Cash and cash equivalents

 

Cash and cash equivalents consists of cash balances and highly liquid investments with original maturities of three months or less that are considered to be cash equivalents. Cash equivalents are held for the purpose of meeting short-term cash commitments rather than for investment or other purposes. Restricted cash is excluded from cash and cash equivalents and is included in other long-term assets

 

Restricted cash

 

Cash which is restricted contractually or which secures various instruments including surety bonds and letters of credit securing reclamation obligations is shown as restricted cash.

 

Inventory

 

In-process inventory represents uranium that has been extracted from the wellfield and captured in the processing plant and is currently being transformed into a saleable product. Plant inventory is U3O8 that is contained in yellowcake, which has been dried and packaged in drums, but not yet shipped to the conversion facility. The amount of U3O8 in the plant inventory is determined by weighing and assaying the amount of U3O8 packaged into drums at the plant. Conversion facility inventory is U3O8 that has been shipped to the conversion facility. The amount of U3O8 in the conversion facility inventory includes the amount of U3O8 contained in drums shipped to the conversion facility plus or minus any final weighing and assay adjustments per the terms of the uranium supplier’s agreement with the conversion facility.

 

The Company’s inventories are measured at the lower of cost or net realizable value and reflect the U3O8 content in various stages of the production and sales process including in-process inventory, plant inventory and conversion facility inventory. Operating supplies are expensed when purchased.

 

Mineral properties

 

Acquisition costs of mineral properties are capitalized. When production is attained, amortization is calculated on a straight-line basis. The original estimated life for the Lost Creek and LC East projects was 10 years which is being used to amortize the mineral property acquisition costs.    

 

If properties are abandoned or sold, they are written off. If properties are considered to be impaired in value, the costs of the properties are written down to their estimated fair value at that time.

 

Exploration, evaluation and development costs

 

Exploration and evaluation expenses consist of labor, annual lease and maintenance fees and associated costs of the exploration geology department as well as exploration costs including drilling and analysis on properties which have not reached the permitting or operations stage.

 

Development expense relates to the Company’s Lost Creek, LC East and Shirley Basin projects, which are more advanced in terms of permitting and preliminary economic assessments. Development expenses include

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

all costs associated with exploring, delineating and permitting within those projects, the costs associated with the construction and development of permitted mine units including wells, pumps, piping, header houses, roads and other infrastructure related to the preparation of a mine unit to begin extraction operations as well as the cost of drilling and completing disposal wells.

 

Capital assets

 

Property, plant and equipment assets, including machinery, processing equipment, enclosures, vehicles and expenditures that extend the life of such assets, are recorded at cost including acquisition and installation costs.  The enclosure costs include both the building housing and the processing equipment necessary for the extraction of uranium from impregnated water pumped in from the wellfield to the packaging of uranium yellowcake for delivery into sales.  These enclosure costs are combined as the equipment and related installation associated with the equipment is an integral part of the structure itself. The costs of self-constructed assets include direct construction costs, direct overhead and allocated interest during the construction phase. Depreciation is calculated using a declining balance method for most assets with the exception of the plant enclosure and related equipment. Depreciation on the plant enclosure and related equipment is calculated on a straight-line basis. Estimated lives for depreciation purposes range from three years for computer equipment and software to 20 years for the plant enclosure and the name plate life of the related equipment.

 

Equity investments

 

Investments in unconsolidated ventures over which the Company has the ability to exercise significant influence, but does not control, are accounted for under the equity method and include the Company’s investments in The Bootheel Project, LLC. The Company identified The Bootheel Project, LLC as a Variable Interest Entity (VIE) as it is dependent on funding from its owners. All voting rights are shared equally on a 50/50 basis between the owners. Therefore, the Company has determined that it is not the primary beneficiary. The Company’s maximum exposure to loss is its equity investment.

 

The equity method is a basis of accounting for investments whereby the investment is initially recorded at cost and the carrying value is adjusted thereafter to include the investor’s pro rata share of post-acquisition earnings or losses of the investee, as computed by the consolidation method. Cash funding increases the carrying value of the investment. Profit distributions received or receivable from an investee reduce the carrying value of the investment.

 

The Bootheel Project, LLC is not a publicly-traded entity. Therefore, the Company assesses whether there has been a potential impairment triggering event for other-than-temporary impairment by testing the underlying asset of the equity investee for recoverability and assess whether there has been a change in the development plan or strategy for the project. If the underlying asset is not recoverable, the Company will record an impairment charge equal to the difference between the carrying amount of the investee and its fair value.

 

Impairment of long-lived assets

 

The Company assesses the possibility of impairment in the net carrying value of its long-lived assets when events or circumstances indicate that the carrying amounts of the asset or asset group may not be recoverable.

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

When potential impairment is indicated, management calculates the estimated undiscounted future net cash flows relating to the asset or asset group using estimated future prices, recoverable resources, and operating, capital and reclamation costs. When the carrying value of an asset exceeds the related undiscounted cash flows, the asset is written down to its estimated fair value, which is determined using discounted future cash flows or other measures of fair value.

 

Asset retirement obligations

 

For mining properties, various federal and state mining laws and regulations require the Company to reclaim the surface areas and restore underground water quality to the pre-existing quality or class of use after the completion of mining. The Company records the fair value of an asset retirement obligation as a liability in the period in which it incurs 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 consist of estimated final well closures, plant closure and removal and associated ground reclamation costs to be incurred by the Company in the future. The estimated fair value of the asset retirement obligation is based on the current cost escalated at an inflation rate and discounted at a credit adjusted risk-free rate. This liability is capitalized as part of the cost of the related asset and amortized over its useful life. The liability accretes until the Company settles the obligation.

 

Revenue recognition

 

The recognition of revenue from the sale of U3O8 is in accordance with the guidelines outlined in ASC Section 605-10-25, Revenue Recognition. The Company delivers U3O8  to a conversion facility and receives credit for the delivery quantity, measured in pounds, less a reserve for variances in the quality of the product delivered.  Once the product is assayed, the credit is adjusted to the full amount calculated. When a delivery is approved, the Company notifies the conversion facility with instructions for a title transfer to the customer. Revenue is recognized once a title transfer of the U3O8  is confirmed by the conversion facility.

 

Occasionally, the Company sells delivery commitments to an independent trader. The proceeds were recorded as deferred revenue until the trader or purchaser acknowledged the deliveries had been made, at which time the portion of the sale relating to those deliveries were taken into sales revenue.  The Company sold two delivery commitments to an independent trader in 2016.  The corresponding deliveries were made in 2016 and the income recognized in that year.

 

Stock-based compensation

 

Stock-based compensation cost from the issuance of stock options and restricted share units (“RSUs”) is measured at the grant date based on the fair value of the award and is recognized over the related service period. Stock-based compensation cost is charged to construction, exploration and evaluation, development, and general and administrative expense on the same basis as other compensation costs.

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Income taxes

 

The Company accounts for income taxes under the asset and liability method which requires the recognition of deferred income tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and tax bases of assets and liabilities. The Company provides a valuation allowance on deferred tax assets unless it is more likely than not that such assets will be realized.

 

Loss per common share

 

Basic loss per common share is calculated based upon the weighted average number of common shares outstanding during the period. The diluted loss per common share, which is calculated using the treasury stock method, is equal to the basic loss per common share due to the anti-dilutive effect of stock options, restricted share units and share purchase warrants outstanding.

 

Classification of financial instruments

 

The Company’s financial instruments consist of cash, short-term investments, accounts receivable, restricted cash, deposits, accounts payable and accrued liabilities, other liabilities and notes payable. The Company has made the following classifications for these financial instruments:

 

·

Cash, accounts receivable, restricted cash and deposits are recorded at amortized cost. Interest income is recorded using the effective interest rate method and is included in income for the period.

·

Accounts payable and accrued liabilities and notes payable are measured at amortized cost.

·

Other liabilities, which related to the derivative on the warrant issued in U.S. dollars, are adjusted to the market value at the end of each reporting period.

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

New accounting pronouncements

 

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”.  The amendments in ASU 2014-09 affect any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance, and creates a Topic 606 Revenue from Contracts with Customers.  The core principle of the guidance is that an entity should recognize revenue to depict the transfer of the promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The amendments are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  Early application is not permitted.  We have reviewed our contracts as well as our procedures and do not anticipate any changes in the manner or timing with which we reflect our revenues.

 

In July 2015, the FASB issued Accounting Standards Update No. 2015-11,  Inventory (Topic 330): Simplifying the Measurement of Inventory.  ASU 2015-11 requires that inventory within the scope of this ASU be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments in this ASU do not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first-out (FIFO) or average cost. For all entities, the guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted. Therefore, the amendments in ASU 2015-11 will become required for us as of the beginning of our 2017 fiscal year. This is consistent with our current policies and is not expected to have a material impact upon our financial condition or results of operations.

 

In January 2016, the FASB issued ASU 2016-1, Recognition and Measurement of Financial Assets and Financial Liabilities (Topic 825). The amendments in this ASU supersede the guidance to classify equity securities with readily determinable fair values into different categories (that is, trading or available-for-sale) and require equity securities (including other ownership interests, such as partnerships, unincorporated joint ventures, and limited liability companies) to be measured at fair value with changes in the fair value recognized through net income. The amendments allow equity investments that do not have readily determinable fair values to be remeasured at fair value either upon the occurrence of an observable price change or upon identification of an impairment. The amendments also require enhanced disclosures about those investments. The amendments improve financial reporting by providing relevant information about an entity’s equity investments and reducing the number of items that are recognized in other comprehensive income. This guidance is effective for annual reporting beginning after December 15, 2017, including interim periods within the year of adoption, and calls for prospective application, with early application permitted. Accordingly, the standard is effective for us beginning in the first quarter of fiscal 2019. The adoption of this guidance is not expected to have a material impact on our consolidated financial statements.

 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize all leases, including operating leases, unless the lease is a short-term lease. ASU 2016-02 also requires additional

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

disclosures regarding leasing arrangements. ASU 2016-02 is effective for interim periods and fiscal years beginning after December 15, 2018, and early application is permitted.  At this time, the only leases we hold are for equipment, office space in one location and a limited number of leases on selected mineral properties.  We do not anticipate the additional disclosures to reflect those leases will have an impact on our statement of financial position as the total future lease payments are not material.

 

In March 2016, the FASB issued ASU No. 2016-09Compensation-Stock Compensation- Improvements to Employee Share-Based Payment Accounting (Topic 718), which involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  Under the new standard, income tax benefits and deficiencies are to be recognized as income tax expense or benefit in the income statement and the tax effects of exercised or vested awards should be treated as discrete items in the reporting period in which they occur.  An entity should also recognize excess tax benefits regardless of whether the benefit reduces taxes payable in the current period.  Excess tax benefits should be classified along with other income tax cash flows as an operating activity.  In regard to forfeitures, the entity may make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. This ASU is effective for fiscal years beginning after December 15, 2016 including interim periods within that reporting period, however early adoption is permitted.  We have reviewed the impact on our financial statements and determined that the effect will be limited to changes in the deferred tax assets and valuation allowances.

 

In November 2016, the FASB issued ASU  No. 2016-18Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Task Force (Topic 230), which addresses the presentation of restricted cash in the statement of cash flows.  Under the new standard, restricted cash will be presented with cash and cash equivalents in the statement of cash flows instead of being reflect as non-cash investing or financing activities.  A reconciliation of the make-up of the end ending cash, cash equivalent and restricted cash balance will be required for entities who reflect restricted cash as separate items on the statement of financial position.  In addition, a description of the restrictions on the cash will be required.  This ASU is effective for fiscal years beginning after December 15, 2017 including interim periods within that reporting period, however early adoption is permitted.  We are currently evaluating the guidance to determine the Company's adoption method and the effect it will have on the Company's Consolidated Financial Statements.

 

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

4.Cash and cash equivalents

 

The Company’s cash and cash equivalents consists of the following:

 

 

 

 

 

 

As at

 

December 31, 2016

    

December 31, 2015

 

$

 

$

Cash on deposit at banks

580

 

1,202

Money market funds

972

 

241

 

 

 

 

 

1,552

 

1,443

 

 

 

 

5.Inventory

 

The Company’s inventory consists of the following:

 

 

 

 

 

 

As at

 

December 31, 2016

 

December 31, 2015

 

$

    

$

In-process inventory

897

 

994

Plant inventory

461

 

742

Conversion facility inventory

2,751

 

1,609

 

 

 

 

 

4,109

 

3,345

 

As of December 31, 2016, there was no inventory carried at excess of net realizable value.  The cost of inventory is recognized as an expense when the corresponding sale is made and the costs are included in Cost of Sales.

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

6.Restricted Cash

 

The Company’s restricted cash consists of the following:

 

 

 

 

 

 

 

 

 

 

As at

 

December 31, 2016

 

December 31, 2015

 

$

    

$

 

 

 

 

Money market account

7,457

 

7,457

Certificates of deposit

100

 

100

 

 

 

 

 

7,557

 

7,557

 

(a)

The bonding requirements for reclamation obligations on various properties have been agreed to by the Wyoming Department of Environmental Quality, United States Department of the Interior and United States Nuclear Regulatory Commission. The restricted money market accounts are pledged as collateral against performance surety bonds which are used to secure the potential costs of reclamation related to those properties. Surety bonds providing $26,688 of coverage towards specific reclamation obligations are collateralized by $7,444 of the restricted cash at December 31, 2016. 

 

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

7. Mineral Properties

 

The Company’s mineral properties consist of the following:

 

 

 

 

 

 

 

 

 

 

 

Lost Creek

 

Pathfinder

 

Other US

 

 

 

Property

 

Mines

 

Properties

 

Total

 

$

 

$

 

$

 

$

 

 

 

 

 

 

 

 

Balance, December 31,  2014

18,512

 

21,028

 

13,210

 

52,750

 

 

 

 

 

 

 

 

Change in estimated reclamation costs (Note 13)

2,391

 

(290)

 

 -

 

2,101

Amortization

(4,241)

 

 -

 

 -

 

(4,241)

 

 

 

 

 

 

 

 

Balance, December 31, 2015

16,662

 

20,738

 

13,210

 

50,610

 

 

 

 

 

 

 

 

Change in estimated reclamation costs (Note 13)

338

 

(872)

 

 -

 

(534)

Property write-offs

 -

 

 -

 

(62)

 

(62)

Amortization

(2,985)

 

 -

 

 -

 

(2,985)

 

 

 

 

 

 

 

 

Balance, December 31, 2016

14,015

 

19,866

 

13,148

 

47,029

 

 

United States

 

Lost Creek Property

 

The Company acquired certain Wyoming properties when Ur-Energy USA Inc. entered into the Membership Interest Purchase Agreement (“MIPA”) with New Frontiers Uranium, LLC in 2005. Under the terms of the MIPA, the Company purchased 100% of NFU Wyoming, LLC. Assets acquired in this transaction include the Lost Creek Project, other Wyoming properties and development databases. NFU Wyoming, LLC was acquired for aggregate consideration of $20 million plus interest. Since 2005, the Company has increased its holdings adjacent to the initial Lost Creek acquisition through staking additional claims and additional property purchases and leases.

 

There is a royalty on each of the State of Wyoming sections under lease at the Lost Creek, LC West and EN Projects, as required by law. Other royalties exist on certain mining claims at the LC South, LC East and EN Projects. There are no royalties on the mining claims in the LC North or LC West Projects.

 

In September 2013, after the Company commenced mineral extraction and production at the Lost Creek Project, it began amortizing the related mineral properties on a straight-line basis.

 

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Pathfinder Mines Corporation

 

The Company acquired additional Wyoming properties when Ur-Energy USA Inc. closed a Share Purchase Agreement (“SPA”) with an AREVA Mining affiliate in December 2013. Under the terms of the SPA, the Company purchased Pathfinder Mines Corporation (“Pathfinder”) to acquire additional mineral properties. Assets acquired in this transaction include the Shirley Basin mine, portions of the Lucky Mc mine, machinery and equipment, vehicles, office equipment and development databases. Pathfinder was acquired for aggregate consideration of $6.7 million, a 5% production royalty under certain circumstances and the assumption of $5.7 million in estimated asset reclamation obligations. The purchase price allocation attributed $5.7 million to asset retirement obligations, $3.3 million to deferred tax liabilities, $15.3 million to mineral properties and the balance to the remaining assets and liabilities.  The royalty expired on June 30, 2016.

 

Other U.S. properties

 

The other US properties include the acquisition cost of several potential mineralized properties including the Lost Soldier Project. The Company continues to maintain those properties through claim payments, lease payments, insurance and other holding costs in anticipation of future exploration efforts.

 

In June 2016, the Company decided to abandon its claims in the Hauber Project and wrote off $62 thousand being the carrying value of the investment in that project.

 

Impairment testing

 

The Company reviews the impairment indicators outlined in GAAP guidance.  In 2016, the sole indication of possible impairment was the decline in industry-wide reported sales price. While this price has no immediate effect on the Company since it has sales contracts until 2021, a cash flow analyses for each of Lost Creek and Shirley Basin was performed. The mine life used was consistent with that reported in the respective NI 43-101 Preliminary Economic Assessment for each property. Cash flows were calculated using a sales price of $30 per pound which was the long-term quoted price in related industry periodicals as of December 31, 2016.  Based on these undiscounted cash flow models, the assets will be recovered and no impairments were indicated for any of the respective properties. 

 

For other properties which have reported mineral resources supported by NI 43-101 Technical Reports, we applied the estimated market pricing to the mineral resource estimates as well as realization percentages which were taken from a previous valuation completed by a third party with respect to the Lost Creek Project in conjunction with obtaining our Wyoming bond loan.

 

Our remaining properties, which have no estimated mineral resource, continue to be carried at their acquisition costs.

 

The Company’s accounting policy is to expense development costs including, but not limited to, production wells, header houses, piping and power as we have no proven and probable reserves.

 

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

8.Capital Assets

 

The Company’s capital assets consist of the following:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of

 

As of

 

December 31, 2016

 

December 31, 2015

 

 

 

Accumulated

 

Net Book

 

 

 

Accumulated

 

Net Book

 

Cost

 

Depreciation

 

Value

 

Cost

 

Depreciation

 

Value

 

$

 

$

 

$

 

$

 

$

 

$

 

 

  

 

  

 

    

 

  

 

  

 

Rolling stock

3,251

 

2,966

 

285

 

3,819

 

3,179

 

640

Enclosures

32,991

 

5,229

 

27,762

 

32,987

 

3,578

 

29,409

Machinery and equipment

1,262

 

599

 

663

 

1,031

 

507

 

524

Furniture, fixtures and leasehold improvements

119

 

98

 

21

 

119

 

92

 

27

Information technology

1,153

 

1,036

 

117

 

1,111

 

923

 

188

 

 

 

 

 

 

 

 

 

 

 

 

 

38,776

 

9,928

 

28,848

 

39,067

 

8,279

 

30,788

 

Total depreciation expense was $3.8 million, $5.1 million and $6.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.

 

9.Equity Investment

 

Following its earn-in to The Bootheel Project, LLC in 2009, Jet Metals Corp, was required to fund 75% of the project’s expenditures and the Company the remaining 25%. The project has been accounted for using the equity accounting method with the Company’s proportionate share of the project’s loss included in the Consolidated Statement of Operations since the date of earn-in and the Company’s net investment is reflected on the Consolidated Balance Sheet. Under the terms of the operating agreement, the Company elected not to participate financially for the project’s financial year ended March 31, 2012 which reduced the Company’s ownership percentage to 19.1%. The equity accounting method has been continued because the Company has an equal number of members on the management committee as the other member and can directly influence the budget, expenditures and operations of the project.

 

In April 2016, the Management Committee of the Bootheel Project determined to continue the ownership and maintenance on the Bootheel property for the fiscal year ending March 31, 2017, which is the fiscal year end of The Bootheel Project, LLC.  No additional exploration or development activities are expected at this time for 2017. Due to the continuing decline in the spot price of uranium combined with the reduction in minerals when the related lease was not renegotiated, the Company examined the valuation of its investment in Bootheel and determined that as a standalone investment, it had an insignificant value and was therefore fully impaired during 2016 resulting in a loss on investment of $1.1 million.

 

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

10.Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities consist of the following:

 

 

 

 

 

 

 

 

 

 

As at

 

December 31, 2016

 

December 31, 2015

 

$

 

$

Accounts payable

725

 

1,402

Severance and ad valorem tax payable

1,649

 

1,992

Payroll and other taxes

1,251

 

1,173

 

 

 

 

 

3,625

 

4,567

 

 

11.Notes Payable

 

On October 15, 2013, the Sweetwater County Commissioners approved the issuance of a $34.0 million Sweetwater County, State of Wyoming, Taxable Industrial Development Revenue Bond (Lost Creek Project), Series 2013 (the “Sweetwater IDR Bond”) to the State of Wyoming, acting by and through the Wyoming State Treasurer, as purchaser. On October 23, 2013, the Sweetwater IDR Bond was issued and the proceeds were in turn loaned by Sweetwater County to Lost Creek ISR, LLC pursuant to a financing agreement dated October 23, 2013 (the “State Bond Loan”). The State Bond Loan calls for payments of interest at a fixed rate of 5.75% per annum on a quarterly basis commencing January 1, 2014. The principal is payable in 28 quarterly installments commencing January 1, 2015 and continuing through October 1, 2021.

 

On March 14, 2014, the Company modified a loan facility with RMB Australia Holding Ltd. (“RMB”) to include a $3.5 million line of credit. On October 15, 2015, the loan was amended to extend the maturity date of the $3.5 million line of credit to December 31, 2016 and spread the $3.5 million balance originally due March 31, 2016 over four quarterly payments commencing March 31, 2016 and concluding December 31, 2016, plus interest at a rate of approximately 9.13%.  This was considered a modification for accounting purposes.  That loan was paid off on December 29, 2016.

 

Deferred loan fees include legal fees, commissions, commitment fees and other costs associated with obtaining the various financings. Those fees amortizable within 12 months of December 31, 2016 are considered current.

 

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

The following table lists the current and long term portion of each of the Company’s debt instruments at December 31, 2016 and December 31, 2015:

 

 

 

 

 

 

As at

 

December 31, 2016

 

December 31, 2015

 

$

 

$

Current debt

 

 

 

Sweetwater County Loan

4,623

 

4,367

RMB First Loan Facility

 -

 

4,312

 

4,623

 

8,679

 

 

 

 

Less deferred financing costs

(121)

 

(152)

 

4,502

 

8,527

 

 

 

 

Long term debt

 

 

 

Sweetwater County Loan

19,891

 

24,514

Less deferred financing costs

(456)

 

(577)

 

19,435

 

23,937

 

Schedule of payments on outstanding debt as of December 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt

Total

 

2017

 

2018

 

2019

 

2020

 

2021

 

Maturity

 

$

 

$

 

$

 

$

 

$

 

$

 

 

Sweetwater County Loan

 

 

 

 

 

 

 

 

 

 

 

 

 

Principal

24,514

 

4,623

 

4,895

 

5,183

 

5,487

 

4,326

 

01-Oct-21

Interest

3,674

 

1,311

 

1,039

 

752

 

447

 

125

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

28,188

 

5,934

 

5,934

 

5,935

 

5,934

 

4,451

 

 

 

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

12.Income Taxes

 

A reconciliation of income taxes at the statutory Canadian income tax rate to net income taxes included in the accompanying statements of operations is as follows:

 

 

 

 

 

 

 

 

Year ended December 31,

 

2016

 

2015

 

2014

 

$

 

$

 

$

Loss before income taxes

(3,027)

 

(4,110)

 

(8,749)

 

 

 

 

 

 

Statutory rate

26.50%

 

26.50%

 

26.50%

Expected recovery of income tax

(804)

 

(1,089)

 

(2,318)

Effect of foreign tax rate differences

(28)

 

(212)

 

(619)

Non-deductible amounts

154

 

57

 

106

Effect of changes in enacted future rates

66

 

76

 

65

Effect of change in foreign exchange rates

 -

 

(155)

 

(186)

Effect of stock based compensation

(149)

 

 -

 

 -

Effect of prior year true-ups and other

(317)

 

 -

 

 -

Expiration of prior year NOLs

290

 

 -

 

-

Change in valuation allowance

771

 

(1,992)

 

2,952

 

(17)

 

(3,315)

 

 -

Recovery of deferred income taxes

 

 

(3,345)

 

 -

 

(17)

 

30

 

 -

 

Deferred tax assets and liabilities reflect the net tax effects of net operating losses, credit carryforwards and temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. The components of the Company’s deferred tax assets and liabilities are as follows:

 

 

 

 

 

 

 

 

As at December 31,

 

2016

 

2015

 

2014

 

$

 

$

 

$

Future income tax assets

 

 

 

 

 

Deferred tax assets

15,344

 

8,386

 

8,074

Net operating loss carry forwards

41,634

 

41,647

 

42,251

Less:  valuation allowance

(56,978)

 

(50,033)

 

(50,325)

 

 -

 

 -

 

 -

Future income tax liabilities

 

 

 

 

 

Mineral properties

 -

 

 -

 

3,345

 

 

 

 

 

 

Net deferred tax liability

 -

 

 -

 

3,345

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Based upon the level of historical taxable loss, management believes it is more likely than not that the Company will not realize the benefits of these deductible differences and accordingly has established a full valuation allowance as of December 31, 2016, 2015 and 2014. No deferred tax assets are therefore recognized at this point.

 

 

 

 

 

 

 

Income tax recovery (expense)

2016

 

2015

 

2014

 

$

 

$

 

$

Recovery of deferred tax liability stemming from Pathfinder acquisition

 -

 

3,345

 

 -

Current income tax recovery (expense)

17

 

(30)

 

 -

 

 

 

 

 

 

 

17

 

3,315

 

 -

 

In 2013, we acquired Pathfinder as a corporate entity.  In terms for the acquisition, there were no net operating losses or other tax attributes that carried forward to the Company with the acquisition.  In addition, the assets acquired had no tax basis within the corporation. The seller also did not make the Sec. 338(h)(10) election to allow us to push the purchase price down to the asset level for tax purposes.  As a result, it was determined that the acquisition should not be treated as a business combination since Pathfinder was not a going concern.  A tax of $3.3 million was calculated as a potential liability of the acquisition and was recorded as a deferred tax liability and an increase in basis. For accounting/reporting purposes, this value was added to the accounting basis in the assets acquired. 

 

In early 2015, we completed and filed the Shirley Basin PEA based on drilling data purchased as a part of the acquisition combined with data gathered during the exploration / confirmation program undertaken in 2014.  After filing the Shirley Basin PEA, we continued to do baseline and confirmation work at Shirley Basin and in late 2015 we submitted a permit application to the state of Wyoming to begin construction and operations at the project.  Based on the filing of those permits, we anticipate that we will be in a position to commence construction of a plant facility and the related wellfields within several years.  Once operations commence, the cost of the property will be amortized over the anticipated productive life of the property for accounting / reporting purposes. At that point, the asset now has an identifiable life and the associated DTL is available to offset the DTA recorded before the application of the valuation allowance. We therefore applied a portion of the valuation allowance to the DTL arising from the Pathfinder acquisition.

 

As of December 31, 2016, the Company had the following net operating loss carryforwards available:

 

 

 

 

 

 

 

Income tax loss carry forwards

 

 

 

 

 

Canadian (expiring 2016 - 2036)

 

 

 

 

$
26,323

United States (expiring 2025 - 2035)

 

 

 

 

$
91,607

 

The Company follows a comprehensive model for recognizing, measuring, presenting and disclosing uncertain tax positions taken or expected to be taken on a tax return. Tax positions must initially be recognized in the financial statements when it is more likely than not the position will be sustained upon examination by the tax authorities. Such tax positions must initially and subsequently be measured as the largest amount of tax benefit

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

that has a greater than 50% likelihood of being realized upon ultimate settlement with the tax authority assuming full knowledge of the position and relevant facts.

 

The Company currently has no uncertain tax positions and is therefore not reflecting any adjustments for such in its deferred tax assets.

 

There are open statutes of limitations for tax authorities in the U.S., Canada and state jurisdictions to audit the Company’s tax returns for the years ended December 31, 2013, 2014 and 2015.

 

The Company’s policy is to account for income tax related interest and penalties in income tax expense in the accompanying statements of operations. There have been no income tax related interest or penalties assessed or recorded.

 

Other comprehensive loss was not subject to income tax effects and is therefore shown net of taxes.

 

13.Asset Retirement Obligations

 

Asset retirement obligations ("ARO") for the Lost Creek Project are equal to the present value of all estimated future costs required to remediate any environmental disturbances that exist as of the end of the period, using discount rates ranging from 0.1% to 3.2%.  Included in this liability are the costs of closure, reclamation, demolition and stabilization of the mine, processing plant, infrastructure, aquifer restoration, waste dumps and ongoing post-closure environmental monitoring and maintenance costs. At December 31, 2016, the total undiscounted amount of the future cash needs was estimated to be $15.0 million. The schedule of payments required to settle the ARO liability extends through 2033.

 

Asset retirement obligations for the Pathfinder properties are equal to the present value of all estimated future costs required to remediate any environmental disturbances that exist as of the end of the period, using discount rates of 2.16% to 3.0%.  Included in this liability are the costs of closure, reclamation, demolition and stabilization of the mines, processing plants, infrastructure, aquifer restoration, waste dumps and ongoing post-closure environmental monitoring and maintenance costs. At December 31, 2016, the total undiscounted amount of the future cash needs was estimated to be $11.5 million. The schedule of payments required to settle the ARO liability extends through 2033.

 

The undiscounted future cash needs are based on information provided to the State of Wyoming in conjunction with annual reclamation bonding renewals.  Increases in the estimated future cash needs are normally based on increased disturbances projected for the upcoming year.  In 2016, there was a small increase in the estimated liability on the Lost Creek Project.

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

The restricted cash as discussed in note 6 is related to surety bonds and letters of credit which provide security to the related governmental agencies on these obligations.

 

 

 

 

 

 

For the year ended

 

Year ended

 

December 31, 2016

 

December 31, 2015

 

 

 

 

 

$

 

$

Beginning of year

26,061

 

23,445

Change in estimated liability

(534)

 

2,101

Accretion expense

534

 

515

 

 

 

 

End of year

26,061

 

26,061

 

 

 

 

14.Shareholders’ Equity and Capital Stock

 

Common share issuances

 

On August 19, 2014, we filed a universal shelf registration statement on Form S-3 in order that we may offer and sell, from time to time, in one or more offerings, at prices and terms to be determined, up to $100 million of our common shares, warrants to purchase our common shares, our senior and subordinated debt securities, and rights to purchase our common shares and/or our senior and subordinated debt securities.  The registration statement became effective September 12, 2014. The 12,921,000 common shares offered in the February 2016 financing were sold for $0.50 per share raising $5.7 million (net of issue costs of $0.8 million) under the shelf registration statement. 

 

On May 27, 2016, we entered into an At Market Issuance Sales Agreement with MLV & Co. LLC and FBR Capital Markets & Co. under which we may, from time to time, issue and sell common shares at market prices on the NYSE MKT or other U.S. market through the distribution agents for aggregate sales proceeds of up to $10,000,000. During 2016, we sold 164,979 common shares under the sales agreement at an average price of $0.65 per share for gross proceeds of $108 thousand. After deducting transaction fees and commissions we received net proceeds of $105 thousand.  After deducting all other costs associated with the completion of the agreement and filing the related prospectus supplement, we received $13 thousand.

 

During the year ended December 31, 2016, the Company exchanged 385,010 common shares for vested Restricted Share Units (“RSUs”). In addition, 16,620 stock options were exercised for proceeds of less than $0.1 million.

 

During the year ended December 31, 2015, the Company exchanged 215,168 common shares for vested RSUs. In addition, 608,531 stock options were exercised for proceeds of $0.4 million.

 

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

During the year ended December 31, 2014, the Company exchanged 182,194 common shares for vested RSUs. In addition, 1,623,139 stock options were exercised for proceeds of $1.3 million.

 

Stock options

 

In 2005, the Company’s Board of Directors approved the adoption of the Company's stock option plan (the “Option Plan”). Eligible participants under the Option Plan include directors, officers, employees and consultants of the Company. Under the terms of the Option Plan, stock options generally vest with Option Plan participants as follows: 10% at the date of grant; 22% four and one-half months after grant; 22% nine months after grant; 22% thirteen and one-half months after grant; and the balance of 24% eighteen months after the date of grant.

 

Activity with respect to stock options is summarized as follows:

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-

 

 

 

 

 

average

 

 

 

Options

 

exercise price

 

 

 

#

 

$

 

 

 

 

 

 

Outstanding, December 31, 2013

 

 

9,273,659

 

1.19

 

 

 

 

 

 

Granted

 

 

1,136,776

 

0.93

Exercised

 

 

(1,623,139)

 

0.83

Forfeited

 

 

(303,612)

 

1.45

Expired

 

 

(15,070)

 

0.82

 

 

 

 

 

 

Outstanding, December 31, 2014

 

 

8,468,614

 

1.12

 

 

 

 

 

 

Granted

 

 

2,384,052

 

0.67

Exercised

 

 

(608,531)

 

0.66

Forfeited

 

 

(258,918)

 

1.09

Expired

 

 

(10,810)

 

0.64

 

 

 

 

 

 

Balance, December 31, 2015

 

 

9,974,407

 

0.88

 

 

 

 

 

 

Granted

 

 

3,062,542

 

0.57

Exercised

 

 

(16,620)

 

0.58

Forfeited

 

 

(788,883)

 

0.70

Expired

 

 

(2,482,512)

 

1.56

 

 

 

 

 

 

Outstanding, December 31, 2016

 

 

9,748,934

 

0.63

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

The exercise price of a new grant is set at the closing price for the stock on the Toronto Stock Exchange (TSX) on the trading day immediately preceding the grant date so there is no intrinsic value as of the date of grant. The fair value of options vested during the year ended December 31, 2016 was $0.7 million.

 

As of December 31, 2016, outstanding stock options are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Options outstanding

 

Options exercisable

 

 

 

 

 

 

Weighted-

 

 

 

 

 

Weighted-

 

 

 

 

 

 

 

 

average

 

 

 

 

 

average

 

 

 

 

 

 

 

 

remaining

 

Aggregate

 

 

 

remaining

 

Aggregate

 

 

Exercise

 

Number

 

contractual

 

Intrinsic

 

Number

 

contractual

 

Intrinsic

 

 

price

 

of options

 

life (years)

 

Value

 

of options

 

life (years)

 

Value

 

Expiry

$

 

 

 

 

 

$

 

 

 

 

 

$

 

 

 

 

 

 

 

 

(thousands)

 

 

 

 

 

(thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

0.68

 

822,659

 

0.0

 

 -

 

822,659

 

0.0

 

 -

 

12-Jan-17

1.04

 

200,000

 

0.1

 

 -

 

200,000

 

0.1

 

 -

 

01-Feb-17

0.88

 

100,000

 

0.2

 

 -

 

100,000

 

0.2

 

 -

 

01-Mar-17

0.57

 

1,129,448

 

0.9

 

 -

 

1,129,448

 

0.9

 

 -

 

07-Dec-17

0.57

 

510,324

 

1.3

 

 -

 

510,324

 

1.3

 

 -

 

25-Apr-18

0.92

 

100,000

 

1.6

 

 -

 

100,000

 

1.6

 

 -

 

01-Aug-18

0.89

 

794,443

 

2.0

 

 -

 

794,443

 

2.0

 

 -

 

27-Dec-18

1.25

 

100,000

 

2.2

 

 -

 

100,000

 

2.2

 

 -

 

31-Mar-19

0.76

 

837,228

 

2.9

 

 -

 

837,228

 

2.9

 

 -

 

12-Dec-19

0.85

 

200,000

 

3.4

 

 -

 

200,000

 

3.4

 

 -

 

29-May-20

0.64

 

709,262

 

3.6

 

 -

 

539,036

 

3.6

 

 -

 

17-Aug-20

0.60

 

1,183,028

 

3.9

 

 -

 

638,837

 

3.9

 

 -

 

11-Dec-20

0.54

 

3,062,542

 

5.0

 

 -

 

306,255

 

5.0

 

 -

 

16-Dec-21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

0.63

 

9,748,934

 

3.0

 

 -

 

6,278,230

 

2.0

 

 -

 

 

 

The aggregate intrinsic value of the options in the preceding table represents the total pre-tax intrinsic value for stock options with an exercise price less than the Company’s TSX closing stock price of CAD $0.71 as of the last trading day in the year ended December 31, 2016, that would have been received by the option holders had they exercised their options as of that date. There were no in-the-money stock options outstanding or exercisable as of December 31, 2016.

 

Restricted share units

 

On June 24, 2010, the Company’s shareholders approved the adoption of the Company’s restricted share unit plan (the “RSU Plan”). The RSU Plan was approved most recently by our shareholders on May 5, 2016.

 

Eligible participants under the RSU Plan include directors and employees, including officers, of the Company. Under the terms of the RSU Plan, RSUs vest with participants as follows: 50% on the first anniversary of the date of the grant and 50% on the second anniversary of the date of the grant.  In March 2015, the Board approved

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

amendments to the plan that (a) extend the redemption period so that, going forward, all RSUs vest 100% on the second anniversary of the date of the grant; (b) provide for redemption, instead of cancellation, of outstanding RSUs at the date of redemption for retiring directors and executive officers, which is defined as a threshold of combined service and age of 65 years, and a minimum of five years of service to the Company; and (c) update the RSU Plan for compliance with applicable laws. The amendments were approved and ratified by shareholder vote on May 28, 2015.  Grants made subsequent to May 28, 2015 have been made pursuant to the described amendments.

 

Activity with respect to RSUs is summarized as follows:

 

 

 

 

 

 

 

 

 

 

Number

 

Weighted

 

 

 

of

 

average grant

 

 

 

RSUs

 

date fair value

 

 

 

 

 

$

Unvested, December 31, 2013

 

 

691,610

 

0.90

 

 

 

 

 

 

Granted

 

 

259,192

 

1.20

Vested

 

 

(527,407)

 

0.74

Forfeited

 

 

(43,960)

 

0.92

 

 

 

 

 

 

Unvested, December 31, 2014

 

 

379,435

 

0.89

 

 

 

 

 

 

Granted

 

 

795,592

 

0.83

Vested

 

 

(286,223)

 

0.91

Forfeited

 

 

(28,709)

 

0.85

 

 

 

 

 

 

Unvested, December 31, 2015

 

 

860,095

 

0.82

 

 

 

 

 

 

Granted

 

 

715,638

 

0.57

Vested

 

 

(281,342)

 

0.81

Forfeited

 

 

(20,401)

 

0.65

 

 

 

 

 

 

Unvested, December 31, 2016

 

 

1,273,990

 

0.60

 

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

As of December 31, 2016, outstanding RSUs are as follows:

 

 

 

 

 

 

 

 

 

 

Number of

 

Remaining

 

Aggregate

 

 

unvested

 

life

 

Intrinsic

Grant date

 

RSUs

 

(years)

 

Value

 

 

 

 

 

 

$

 

 

 

 

 

 

(thousands)

March 13, 2015

 

110,278

 

0.19

 

58

August 17, 2015

 

177,314

 

0.62

 

94

December 11, 2015

 

270,760

 

0.94

 

144

December 16, 2016

 

715,638

 

1.95

 

379

 

 

 

 

 

 

 

 

 

1,273,990

 

0.84

 

675

 

As of December 31, 2016, 8,374 RSUs had been vested and redeemed but not issued due to the timing of transferring them to the brokers designated by the related employees.  They were subsequently issued in January and February 2017.

 

As of December 31, 2015, 212,803 RSUs had been vested but not redeemed.  In January 2016, 197,374 were redeemed for common shares while the balance of 15,429 were retained and not redeemed to pay the related taxes due on redemption.

 

As of December 31, 2014, 280,529 RSUs had been vested but not redeemed.  In January 2015, 215,168 were redeemed for common shares while the balance of 65,361 were retained and not redeemed to pay the related taxes due on redemption.

 

Upon RSU vesting, the holder of an RSU will receive one common share, for no additional consideration, for each RSU held.

 

Warrants

 

The warrants were issued in Canadian dollars and have been converted to their US$ equivalent for presentation purposes. The First Loan Facility accounts for the warrants expiring in 2018.

 

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Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Activity with respect to warrants is summarized as follows:

 

 

 

 

 

 

 

 

 

 

Number

 

Weighted-

 

 

 

of

 

average

 

 

 

Warrants

 

exercise price

 

 

 

 

 

$

Outstanding, December 31, 2013

 

 

8,374,112

 

0.95

 

 

 

 

 

 

Outstanding, December 31, 2014

 

 

8,374,112

 

1.20

 

 

 

 

 

 

Expired

 

 

(150,000)

 

0.89

 

 

 

 

 

 

Outstanding, December 31, 2015

 

 

8,224,112

 

1.71

 

 

 

 

 

 

Expired

 

 

(2,379,545)

 

1.34

 

 

 

 

 

 

Outstanding, December 31, 2016

 

 

5,844,567

 

1.02

 

As of December 31, 2016, outstanding warrants are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Remaining

 

Aggregate

 

 

Exercise

 

Number

 

contractual

 

Intrinsic

 

 

price

 

of warrants

 

life (years)

 

Value

 

Expiry

$

 

 

 

 

 

$

 

 

 

 

 

 

 

 

(thousands)

 

 

0.89

 

4,294,167

 

1.7

 

 -

 

24-Jun-18

0.93

 

1,550,400

 

1.9

 

 -

 

27-Aug-18

 

 

 

 

 

 

 

 

 

0.90

 

5,844,567

 

1.3

 

 -

 

 

 

Share-based compensation expense

 

Stock-based compensation expense was $0.9 million, $0.9 million and $0.9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

 

As of December 31, 2016, there was approximately $0.9 million of total unrecognized compensation expense (net of estimated pre-vesting forfeitures) related to unvested share-based compensation arrangements granted under the Option Plan and $0.6 million under the RSU Plan. The expenses are expected to be recognized over a weighted-average period of 1.3 years and 1.6 years, respectively.

 

Cash received from stock options exercised during the years ended December 31, 2016, 2015 and 2014 was less than $0.1 million, $0.4 million and $1.3 million, respectively.

 

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Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Fair Value Calculations

 

The initial fair value of RSUs, options and warrants granted during the years ended December 31, 2016, 2015 and 2014 was determined using the Black-Scholes option pricing model with the following assumptions:

 

 

 

 

 

 

2016

2015

2014

 

 

   

 

Expected option life (years)

3.72

3.6-3.67

3.49-3.56

Expected volatility

57%

55-57%

61-66%

Risk-free interest rate

1.0%

0.5-0.7%

1.1-1.4%

Forfeiture rate (options)

5.6%

4.9-5.0%

4.5-4.7%

Forfeiture rate (RSUs)

6.2%

7.2-8.3%

7.7%

Expected dividend rate

0%

0%

0%

 

The Company estimates expected volatility using daily historical trading data of the Company’s common shares, because this is recognized as a valid method used to predict future volatility. The risk-free interest rates are determined by reference to Canadian Treasury Note constant maturities that approximate the expected option term. The Company has never paid dividends and currently has no plans to do so.

 

Share-based compensation expense is recognized net of estimated pre-vesting forfeitures, which results in recognition of expense on options that are ultimately expected to vest over the expected option term. Forfeitures were estimated using actual historical forfeiture experience.

 

The fair value used for each RSUs issued in 2016 was CAD $0.73. Those issued in 2015 ranged from CAD $0.80 to CAD $1.22 per unit, while the RSUs issued in December 2014 were $0.96 per unit.  Each of the issuance prices were the closing prices of the stock on the TSX as of the trading day immediately preceding the grant date.

 

15.Sales

 

Revenue is primarily derived from the sale of U3O8 to domestic utilities under contracts or spot sales. In 2016, the Company also sold deliveries under two of its contracts to a third party trader. The income was deferred at the time and recognized when the respective deliveries were completed.

 

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Table of Contents

Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Revenue consists of:

 

 

 

 

 

 

 

 

 

 

Year ended December 31,

 

2016

 

2015

 

$

 

 

 

$

 

 

Sale of produced inventory

 

 

 

 

 

 

 

Company  A

12,741

 

46.7%

 

6,098

 

14.6%

Company B

6,375

 

23.3%

 

6,518

 

15.6%

Company C

3,075

 

11.3%

 

10,674

 

25.4%

Company D

 -

 

0.0%

 

6,671

 

15.9%

 

22,191

 

81.3%

 

29,961

 

71.5%

Sales of purchased inventory

 

 

 

 

 

 

 

Company E

 -

 

0.0%

 

11,847

 

28.3%

 

 

 

 

 

 

 

 

Total sales

22,191

 

81.3%

 

41,808

 

99.8%

 

 

 

 

 

 

 

 

Disposal fee income

29

 

0.1%

 

69

 

0.2%

Recognition of revenue from sale of deliveries under assignment

5,085

 

18.6%

 

 -

 

0.0%

 

 

 

 

 

 

 

 

 

27,305

 

100.0%

 

41,877

 

100.0%

 

 

16.Financial instruments

 

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, restricted cash, deposits, accounts payable and accrued liabilities and notes payable. The Company is exposed to risks related to changes in foreign currency exchange rates, interest rates and management of cash and cash equivalents and short-term investments.

 

Credit risk

 

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents and restricted cash. These assets include Canadian dollar and U.S. dollar denominated certificates of deposits, money market accounts and demand deposits. These instruments are maintained at financial institutions in Canada and the United States. Of the amount held on deposit, approximately $0.6 million is covered by the Canada Deposit Insurance Corporation, the Securities Investor Protection Corporation or the United States Federal Deposit Insurance Corporation, leaving approximately $8.5 million at risk at December 31, 2016 should the financial institutions with which these amounts are invested be rendered insolvent. The Company does not consider any of its financial assets to be impaired as of December 31, 2016.

 

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Table of Contents

Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

Liquidity risk

 

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due.

 

The Company has financed its operations from its inception primarily through the issuance of equity securities and debt instruments. Production commenced in August 2013 after receiving final operational clearance from the NRC. Product sales commenced in December 2013.

 

As at December 31, 2016, the Company’s financial liabilities consisted of trade accounts payable and accrued trade and payroll liabilities of $1.3 million which are due within normal trade terms of generally 30 to 60 days, notes payable which will be payable over periods of 0 to 5 years, and asset retirement obligations with estimated completion dates until 2033.

 

Market risk

 

Market risk is the risk to the Company of adverse financial impacts due to changes in the fair value or future cash flows of financial instruments as a result of fluctuations in interest rates and foreign currency exchange rates.

 

Interest rate risk

 

Financial instruments that expose the Company to interest rate risk are its cash equivalents, deposits, restricted cash and debt financings. The Company’s objectives for managing its cash and cash equivalents are to maintain sufficient funds on hand at all times to meet day to day requirements and to place any amounts considered in excess of day to day requirements on short-term deposit with the Company's financial institutions so that they earn interest.

 

Currency risk

 

The Company maintains a balance of less than $0.1 million in foreign currency resulting in a low currency risk.

 

Sensitivity analysis

 

The Company has completed a sensitivity analysis to estimate the impact that a change in interest rates would have on the net loss of the Company. This sensitivity analysis shows that a change of +/- 100 basis points in interest rate would have a $0.1 million impact for the year ended December 31, 2016. The financial position of the Company may vary at the time that a change in interest rates occurs causing the impact on the Company’s results to differ from that shown above.

 

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Table of Contents

Ur-Energy Inc.

Notes to Consolidated Financial Statements

December 31, 2016

 

(expressed in thousands of U.S. dollars unless otherwise indicated)

17.Commitments

 

Under the terms of its operating lease for vehicles and the office premises in Casper, Wyoming, the Company is committed to minimum annual lease payments as follows:

 

 

 

Year ended December 31,

$

2017

288

2018

188

2019 and thereafter

 -

 

476

 

Rent expense under these agreements was $0.2 million, $0.2 million and $0.2 million for the years ended December 31, 2016, 2015 and 2014, respectively.

 

Principal payments required under debt agreements are as follows:

 

 

 

Year ended:

 

31-Dec-17

4,623

31-Dec-18

4,895

31-Dec-19

5,183

31-Dec-20

5,487

31-Dec-21

4,326

 

24,514

 

Off Take Sales Agreements

 

As of December 31, 2016, we have multiple off take sales agreements with various U.S. utilities. These agreements were completed between 2012 and 2015 for deliveries between 2017 and 2021 as follows: 

 

 

 

SUMMARY OF OFF TAKE SALES AGREEMENTS

Production Year

Total Pounds Uranium Concentrates Contractually Committed

2017

600,000 pounds

2018

500,000 pounds

2019

600,000 pounds

2020

450,000 pounds

2021

250,000 pounds

 

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