UR-ENERGY INC - Quarter Report: 2015 June (Form 10-Q)

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United States

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☑

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015

☐

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: 333-193316

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

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 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 July 30, 2015, there were 130,184,563 shares of the registrant’s no par value Common Shares (“Common Shares”), the registrant’s only outstanding class of voting securities, outstanding.

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UR-ENERGY INC.

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		Page

	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 4.	Controls and Procedures	41

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	43

SIGNATURES

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When we use the terms “Ur-Energy,” “we,” “us,” or “our,” or the “Company” we are referring to Ur-Energy Inc. and its subsidiaries, unless the context otherwise requires. Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Cautionary Statement Regarding Forward-Looking Statements” section of this document for an explanation of these types of assertions.

Cautionary Statement Regarding Forward-Looking Information

This report on Form 10-Q 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 reach and maintain production operations at design capacity at Lost Creek; (ii) the technical and economic viability of Lost Creek; (iii) our ability to complete additional favorable uranium sales agreements including spot sales if production is available and the market warrants; (iv) the production rates and life of the Lost Creek Project and subsequent production from adjoining properties, including LC East; (v) the potential of exploration targets throughout the Lost Creek Property (including the ability to expand resources); (vi) the potential of our other exploration and development projects, including Shirley Basin, as well as the technical and economic viability of Shirley Basin; (vii) the timing and outcome of permitting and regulatory approvals at Shirley Basin; (viii) the outcomes of our 2015 guidance and production projections; and (ix) 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, production start-up and operations, capital expenditures, operating costs, mineral resources, recovery rates, grades and 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 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 pending and 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 status as a "controlled foreign corporation" 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” and under the heading of “Risk Factors” in our Annual Report on Form 10-K, dated March 2, 2015.

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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 United States standards.

NI 43-101 Review of Technical Information: John Cooper, Ur-Energy Project Geologist, P.Geo. and SME Registered Member, and Qualified Person as defined by National Instrument 43-101 reviewed and approved the technical information contained in this Quarterly Report on Form 10-Q.

PART I

Item 1. FINANCIAL STATEMENTS

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Ur-Energy Inc.

Unaudited Interim Consolidated Balance Sheets

(expressed in thousands of U.S. dollars)


	June 30,	December 31,
	2015	2014
Assets
Current assets
Cash and cash equivalents (note 4)	3,851	3,104
Accounts receivable	12	28
Inventory (note 5)	3,885	5,168
Prepaid expenses	917	856
	8,665	9,156

Restricted cash (note 6)	7,556	7,556
Mineral properties (note 7)	50,161	52,750
Capital assets (note 8)	31,892	32,993
Equity investment (note 9)	1,089	1,090
	90,698	94,389
	99,363	103,545
Liabilities and shareholders' equity
Current liabilities
Accounts payable and accrued liabilities (note 10)	4,195	4,532
Current portion of notes payable (note 11)	10,008	7,184
Reclamation obligations	85	85
	14,288	11,801
Notes payable (note 11)	26,090	32,477
Deferred income tax liability (note 12)	3,345	3,345
Asset retirement obligations (note 13)	23,699	23,445
Other liabilities - warrants (note 14)	185	376
	53,319	59,643
	67,607	71,444
Shareholders' equity (note 15)
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: 130,184,563 at June 30, 2015 and 129,365,076 at December 31, 2014	168,907	168,118
Warrants	4,175	4,175
Contributed surplus	14,197	14,250
Accumulated other comprehensive income	3,355	3,337
Deficit	(158,878)	(157,779)
	31,756	32,101
	99,363	103,545

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

Approved by the Board of Directors

/s/ Jeffrey T. Klenda, Chairman of the Board/s/ Thomas Parker, Director

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Ur-Energy Inc.

Unaudited Interim Consolidated Statements of Operations and Comprehensive Loss

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


	Three months ended June 30,		Six months ended June 30,
	2015	2014	2015	2014

Sales (note 16)	18,213	9,236	25,600	15,383

Cost of sales	(13,791)	(7,169)	(19,181)	(10,409)

Gross profit	4,422	2,067	6,419	4,974

Operating Expenses

Exploration and evaluation	(550)	(854)	(1,235)	(1,872)
Development	(557)	(711)	(1,586)	(1,285)
General and administrative	(1,743)	(1,335)	(3,260)	(3,647)
Accretion	(128)	(39)	(254)	(77)
Write-off of mineral properties	-	(93)	-	(93)

Profit (loss) from operations	1,444	(965)	84	(2,000)

Interest expense (net)	(658)	(675)	(1,346)	(1,311)
Warrant mark to market adjustment (note 14)	248	839	171	576
Loss on equity investment (note 9)	(5)	(3)	(5)	(3)
Foreign exchange loss	(4)	-	(3)	(14)

Net profit (loss) for the period	1,025	(804)	(1,099)	(2,752)

Profit (loss) per common share
Basic and diluted	0.01	(0.01)	(0.01)	(0.02)

Weighted average number of common shares outstanding
Basic and diluted	130,135,611	128,741,134	129,923,742	128,422,858

COMPREHENSIVE PROFIT (LOSS)
Net profit (loss) for the period	1,025	(804)	(1,099)	(2,752)
Other Comprehensive loss, net of tax
Translation adjustment on foreign operations	(8)	(33)	18	2

Comprehensive profit (loss) for the period	1,017	(837)	(1,081)	(2,750)

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

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Ur-Energy Inc.

Unaudited Interim Consolidated Statement 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, 2014	129,365,076	168,118	4,175	14,250	3,337	(157,779)	32,101

Exercise of stock options	604,319	621	-	(214)	-	-	407
Redemption of vested RSUs	215,168	167	-	(295)	-	-	(128)
Non-cash stock compensation	-	-	-	457	-	-	457
Net loss and comprehensive income	-	-	-	-	18	(1,099)	(1,081)

Balance, June 30, 2015	130,184,563	168,907	4,175	14,197	3,355	(158,878)	31,756

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

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Ur-Energy Inc.

Unaudited Interim Consolidated Statements of Cash Flow

(expressed in thousands of U.S. dollars)


	Six months ended June 30,
	2015	2014

Cash provided by (used in)
Operating activities
Net loss for the period	(1,099)	(2,752)
Items not affecting cash:
Stock based expense	457	531
Depreciation and amortization	3,735	3,838
Accretion expense	254	77
Amortization of deferred loan costs	94	7
Write-off of mineral properties	-	93
Warrants mark to market loss	(171)	(576)
Other loss	5	3
RSUs redeemed for cash	(143)	(66)
Proceeds from assignment of sales contract	-	(1,254)
Change in non-cash working capital items:
Accounts receivable	15	(1,441)
Inventory	1,283	(148)
Prepaid expenses	(230)	130
Accounts payable and accrued liabilities	(171)	548
	4,029	(1,010)

Investing activities
Mineral property costs	-	(58)
Funding of equity investment	-	(7)
Purchase of capital assets	(43)	(310)
	(43)	(375)

Financing activities
Share issue costs	-	(50)
Proceeds from exercise of stock options	408	880
Proceeds from debt financing	-	1,500
Cost of debt financing	-	(37)
Repayment of debt	(3,658)	(965)
	(3,250)	1,328

Effects of foreign exchange rate changes on cash	11	(16)

Net change in cash and cash equivalents	747	(73)
Beginning cash and cash equivalents	3,104	1,627
Ending cash and cash equivalents	3,851	1,554

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

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

1.Nature of Operations

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

Due to the nature of the uranium mining methods we use on the Lost Creek Property, and the definition of “mineral reserves” under the SEC Industry Guide 7, the Company has not determined whether the Lost Creek Property contains mineral reserves. However, the Company’s June 17, 2015 NI 43-101 “Technical Report for the Lost Creek Property, Sweetwater County, Wyoming,” outlines the potential viability of the Lost Creek Property. As well, the Company’s January 27, 2015 NI 43-101 Technical Report on Shirley Basin, “Preliminary Economic Assessment of Shirley Basin Uranium Project Carbon County, Wyoming, USA” (the “Shirley Basin PEA”), outlines the potential viability of the Shirley Basin Project. 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

The Company has financed its operations from its inception primarily through the issuance of equity securities and debt instruments. Construction and development of the Lost Creek Project commenced in October 2012 after receiving the Record of Decision from the U.S. Department of the Interior Bureau of Land Management (“BLM”). Production began in August 2013 after receiving final operational clearance from the U.S. Nuclear Regulatory Commission (“NRC”). The Company made its first deliveries and related sales in December 2013. It is now generating funds from sales to finance its operations.

Based upon the Company’s current working capital balances and the expected timing of contractual product sales, it is possible that additional funding may be sought. During the quarter, the Company accelerated a contractual delivery from September to April and delivered under the contract using purchased U₃O₈. Also during the quarter, the Company conducted its first spot priced sale in June and delivered under the sale using produced U₃O₈. These are examples of the methods the Company may use to mitigate short term cash flow timing issues utlizing internal resources as opposed to obtaining additional external funding. The Company has no immediate plans to raise debt or equity financing, but may do so in the future. 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.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

(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. All inter-company balances and transactions between the subsidiaries and/or the parent have been eliminated upon consolidation.

These unaudited interim consolidated financial statements do not conform in all respects to the requirements of generally accepted accounting principles for annual financial statements. The unaudited interim financial statements reflect all normal adjustments which in the opinion of management are necessary for a fair statement of the results for the periods presented. These unaudited interim consolidated financial statements should be read in conjunction with the audited annual consolidated financial statements for the year ended December 31, 2014.

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 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 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, 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 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 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.

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 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.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

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.

New accounting pronouncements

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU”) 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal periods beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. We have elected early adoption of this standard effective with these financial statements. The impact was to move $174 thousand from current deferred loan costs to offset the current portion of the long term debt and to move $638 thousand of deferred loan costs previously included in non-current assets to offset the long term portion of the notes payable as of June 30, 2015. As at December 31, 2014, we moved $190 thousand of current deferred cost to offset the current portion of long-term debt and $716 thousand of non-current deferred loan costs to offset non-current notes payable. See note 11.

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 ptherromised 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 were to be effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In June 2015, the FASB extended the implementation implementation date for one year to December 15, 2017. Early application is not permitted. The Company does not currently have contracts or other arrangements with customers which would be affected by this Standard. It will continue monitoring the final terms of the standard and assessing any impact on revenue recognition as appropriate.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

4Cash and Cash Equivalents

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


	As of June 30,	As of December 31,
	2015	2014
	$	$
Cash on deposit at banks	2,355	431
Money market funds	1,496	2,673

	3,851	3,104

5.Inventory

The Company’s inventory consists of the following:


	As of June 30,	As of December 31,
	2015	2014
	$	$
In-process inventory	1,219	2,084
Plant inventory	851	882
Conversion facility inventory	1,815	2,202

	3,885	5,168

As of June 30, 2015, there was no inventory on hand with costs in excess of net realizable value.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

6.Restricted Cash

The Company’s restricted cash consists of the following:


	As of June 30,	As of December 31,
	2015	2014
	$	$

Money market account (a)	7,456	7,456
Certificates of deposit (b)	100	100

	7,556	7,556

(a) The bonding requirements for reclamation obligations on various properties have been agreed to by the Wyoming Department of Environmental Quality (“WDEQ”), the BLM and the NRC. 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 $26.7 million of coverage towards specific reclamation obligations are collateralized by $7.5 million of the restricted cash at June 30, 2015.

(b) The certificate of deposit provides security for the Company’s credit cards.

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

Amortization	(2,589)	-	-	(2,589)

Balance, June 30, 2015	15,923	21,028	13,210	50,161

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

Lost Creek Property

The Company acquired certain Wyoming properties in 2005 when Ur-Energy USA Inc. 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 and EN Projects. There are no royalties on the mining claims in the Lost Creek, LC North, LC East or LC West Projects.

Pathfinder Mines

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”). Assets acquired in this transaction include the Shirley Basin Mine Project, portions of the Lucky Mc Mine, machinery and equipment, vehicles, office equipment, and exploration and development databases. Pathfinder was acquired for aggregate consideration of $6.6 million, a 5% production royalty under certain circumstances and the assumption of certain asset reclamation obligations which were estimated by AREVA at $5.7 million. Additional royalties exist on certain of the mineral properties at Shirley Basin as described in the January 2015 Shirley Basin PEA. 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.

8.Capital Assets

The Company’s capital assets consist of the following:


	As of			As of
	June 30, 2015			December 31, 2014
		Accumulated	Net Book		Accumulated	Net Book
	Cost	Depreciation	Value	Cost	Depreciation	Value
	$	$	$	$	$	$

Rolling stock	3,881	3,045	836	3,878	2,852	1,026
Enclosures	32,987	2,753	30,234	32,968	1,927	31,041
Machinery and equipment	1,004	466	538	992	426	566
Furniture, fixtures and leasehold improvements	119	88	31	119	81	38
Information technology	1,122	869	253	1,119	797	322

	39,113	7,221	31,892	39,076	6,083	32,993

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

9.Equity Investment

Following its earn-in to the Bootheel Project 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 pro rata share of the project’s loss included in the Statement of Operations since the date of earn-in and the Company’s net investment is reflected on the Balance Sheet. Under the terms of the operating agreement, the Company elected not to participate financially for the year ended June 30, 2012 which reduced the Company’s ownership percentage to approximately 19%. 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.

10.Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consist of the following:



	As of June 30,	As of December 31,
	2015	2014
	$	$
Accounts payable	1,045	1,503
Severance and ad valorem tax payable	1,686	1,947
Payroll and other taxes	1,464	1,082

	4,195	4,532

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. The State Bond Loan is collateralized by all of the assets at the Lost Creek Project. As a condition of the financing, earlier loan facilities with RMB Australia Holding Ltd (“RMBAH”) together with certain construction equipment loans were paid off with the funding proceeds from the State Bond Loan.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

On June 24, 2013, the Company entered into a $20.0 million First Loan Facility with RMBAH. The initial $20.0 million was drawn and repaid during 2013. An amendment to the First Loan Facility allowed for $5.0 million to be redrawn. This was done on December 19, 2013 for the acquisition of Pathfinder. On March 14, 2014, the loan was amended to change the interest rate, extend the loan maturity date to March 31, 2016 and increase the current loan to $10.0 million which included an additional line of credit of $3.5 million as a result of the completion and results of the Technical Report (NI 43-101) on the newly acquired Shirley Basin Project. On March 14, 2014, the Company also drew down an additional $1.5 million on its First Loan Facility. On September 19, 2014, the Company drew down the $3.5 million line of credit. The amended interest rate is approximately 8.75%. Principal payments of $0.81 million are due quarterly. The line of credit is renewable until March 31, 2016.

Deferred loan fees includes legal fees, commissions, commitment fees and other costs associated with obtaining the various financings. Those fees amortizable within 12 months of June 30, 2015 are considered current. The current and long-term deferred loan fees have been offset against the related liabilities in accordance with recently approved ASU 2015-03 which we have elected to adopt early in these financial statements See note 3.

The following table lists the current (within 12 months) and long term portion of each of the Company’s debt instruments:


	As at	As at
	June 30, 2015	December 31, 2014
Current debt
Sweetwater County bond	4,245	4,124
RMBAH First Loan Facility	5,937	3,250
	10,182	7,374

Less deferred financing costs	(174)	(190)
	10,008	7,184

Long term debt
Sweetwater County bond	26,728	28,881
RMBAH First Loan Facility	-	4,312
	26,728	33,193

Less deferred financing costs	(638)	(716)
	26,090	32,477

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

Schedule of payments on outstanding debt as of June 30, 2015:



Debt	Total	2015	2016	2017	2018	2019	Subsequent	Maturity
Sweetwater County bond
Principal	30,973	2,092	4,367	4,623	4,895	5,183	9,813	October 1, 2021
Interest	6,118	876	1,568	1,311	1,039	752	572

RMBAH First Loan Facility
Principal	5,937	1,625	4,312	-	-	-		March 31, 2016
Interest	343	248	95	-	-	-

Total	43,371	4,841	10,342	5,934	5,934	5,935	10,385

12.Income Taxes and Deferred Income Taxes

The deferred income tax liability relates to the acquisition of Pathfinder. When the Company acquired Pathfinder, it had no basis in its remaining assets. Accordingly, the Company has no tax basis in these assets. Under US GAAP, the Company has to record a liability for the estimated additional taxes that would arise on the disposition of those assets because of the lack of tax basis in those assets.

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 not reflected any deferred income tax assets.

13.Asset Retirement and Reclamation Obligations

Asset retirement obligations ("ARO") relate to the Lost Creek Project and Pathfinder and 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 discounted at a risk-free rate. 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 June 30, 2015, the total undiscounted amount of the future cash needs was estimated to be $24.8 million. The schedule of payments required to settle the ARO liability extends through 2033.

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

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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


	Six months ended	Year ended
	June 30, 2015	December 31, 2014

	$	$
Beginning of year	23,445	17,279
Change in estimated liability	-	5,669
Accretion expense	254	497

End of period	23,699	23,445

14.Other Liabilities - Warrants

For the December 2013 private placement, we issued units consisting of one common share of the Company’s stock and one half warrant. Each full warrant is priced at US$1.35 which created a derivative financial instrument as it is exerciseable in a currency other than the parent company’s functional currency. The liability created is adjusted to a calculated fair value quarterly using the Black-Scholes technique described below as there is no active market for the warrants. Any income or loss is reflected in net income for the year. The revaluation as of June 30, 2015 resulted in gains of $248 and $171 thousand for the three and six months ended June 30, 2015, respectively, which is reflected on the statement of operations.

15.Shareholders’ Equity and Capital Stock

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.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

Activity with respect to stock options is summarized as follows:


		Weighted-
	Options	average
	#	exercise price
		US$

Outstanding, December 31, 2014	8,468,614	1.12

Granted	200,000	0.92
Exercised	(604,319)	0.68
Forfeited	(94,361)	0.91
Expired	(10,810)	0.66

Outstanding, June 30, 2015	7,959,124	1.08

The exercise price of a new grant is set at the closing price for the shares 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 six months ended June 30, 2015 was $0.4 million.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

As of June 30, 2015, outstanding stock options are as follows:


	Options outstanding			Options exercisable
		Weighted-			Weighted-
		average	Aggregate		average	Aggregate
Exercise		remaining	Intrinsic		remaining	Intrinsic
price	Number	contractual	Value	Number	contractual	Value
US$	of options	life (years)	US$	of options	life (years)	US$	Expiry
			(thousands)			(thousands)

2.32	1,220,276	0.6	-	1,220,276	0.6	-	January 28, 2016
1.27	545,000	1.0	-	545,000	1.0	-	July 7, 2016
0.95	627,117	1.2	-	627,117	1.2	-	September 9, 2016
0.94	200,000	1.3	-	200,000	1.3	-	October 24, 2016
0.74	914,135	1.5	31	914,135	1.5	31	January 12, 2017
1.12	200,000	1.6	-	200,000	1.6	-	February 1, 2017
0.95	100,000	1.7	-	100,000	1.7	-	March 1, 2017
0.62	1,266,496	2.4	174	1,266,496	2.4	174	December 7, 2017
0.62	567,684	2.8	78	567,684	2.8	78	April 25, 2018
1.00	100,000	3.1	-	100,000	3.1	-	August 1, 2018
0.97	925,060	3.5	-	925,060	3.5	-	December 27, 2018
1.36	100,000	3.8	-	76,000	3.8	-	March 31, 2019
0.83	993,356	4.5	-	377,115	4.5	-	December 12, 2019
0.92	200,000	4.9		20,000	4.9		May 29, 2020

1.08	7,959,124	2.5	283	7,138,883	2.2	283

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 Cdn$0.97 as of the last trading day in the period ended June 30, 2015, that would have been received by the option holders had they exercised their options as of that date. The total number of in-the-money stock options outstanding as of June 30, 2015 was 2,748,315. The total number of in-the-money stock options exercisable as of June 30, 2015 was 2,748,315.

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 plan was approved most recently, as amended, on April 25, 2013.

Eligible participants under the RSU Plan include directors and employees of the Company. Under the terms of the original RSU Plan, RSUs vested 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 amendments to the plan that (a) extend the redemption period so that, going forward, all RSUs in a grant are not redeemed until the second anniversary of the grant; (b) provide for redemption, instead of cancellation, of outstanding RSUs at the date of

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

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 at our most recent annual meeting of shareholders.

Activity with respect to RSUs is summarized as follows:


	Number	Weighted
	of	average grant
	RSUs	date fair value
		US$
Unvested, December 31, 2014	379,435	0.89

Granted	274,574	0.99
Vested	(73,420)	0.94
Forfeited	(14,735)	0.87

Unvested, June 30, 2015	565,854	0.92

As of June 30, 2015, outstanding RSUs are as follows:


			Aggregate
	Number of	Remaining	Intrinsic
	unvested	life	Value
Grant date	RSUs	(years)	US$
			(thousands)
December 27, 2013	104,344	0.49	81
December 12, 2014	227,902	1.45	178
March 13, 2015	233,608	1.70	182

	565,854	1.38	441

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

Warrants

There was no warrant activity during the period ended June 30, 2015.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

As of June 30, 2015, outstanding warrants are as follows:


			Aggregate
Exercise		Remaining	Intrinsic
price	Number	contractual	Value
US$	of warrants	life (years)	US$	Expiry
			(thousands)

0.92	50,000	0.2	-	September 4, 2015
1.12	100,000	0.3	-	November 1, 2015
0.93	25,000	0.7	-	March 5, 2016
1.35	2,354,545	1.5	-	December 19, 2016
1.12	4,294,167	3.0	-	June 24, 2018
1.17	1,550,400	3.2	-	August 27, 2018

1.19	8,374,112	2.8	-

Share-based compensation expense

Share-based compensation expense was $0.4 million and $0.6 million for the three and six months ended June 30, 2015, repectively and $0.2 million and $0.6 million for the three and six months ended June 30, 2014, respectively.

As of June 30, 2015, there was approximately $0.4 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 $0.4 million under the RSU Plan. The expenses are expected to be recognized over a weighted-average period of 1.0 years and 1.4 years, respectively.

Cash received from stock options exercised during the six months ended June 30, 2015 and 2014 was $0.4 million and $0.9 million, respectively.

Fair value calculations

The fair value of RSUs granted during the six months ended June 30, 2015 was determined using the intrinsic value method using a forfeiture rate of 7.81% based on historical data. The initial fair value of options granted during the six

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

months ended June 30, 2015 and 2014 was determined using the Black-Scholes option pricing model. The following assumptions were used in the calculations:


	Six months ended June 30,
	2015	2014
Expected option life (years)	3.60	3.49
Expected volatility	57.00%	66.00%
Risk-free interest rate	0.67%	1.40%
Expected dividend rate	0%	0%
Forfeiture rate (Options)	5.0%	4.5%

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.

There were no RSUs granted in the six months ended June 30, 2014.

16. Sales

Sales have been derived from U₃O₈ being sold to domestic utilities, primarily under term contracts.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

Sales consist of:


	Six months ended June 30,
	2015		2014
	$		$
Sale of produced inventory
Company A	6,098	23.7%	4,127	26.8%
Company B	5,094	19.9%	7,197	46.8%
Company C	2,555	10.0%	-	0.0%
Company D	-	0.0%	2,596	16.9%
	13,747	53.7%	13,920	90.5%
Sales of purchased inventory
Company E	11,846	46.3%	-	0.0%

Total sales of inventory	25,593	100.0%	13,920	54.4%

Disposal fees	7	0.0%	209	1.4%
Recognition of gain from sale of deliveries under assignment	-	0.0%	1,254	8.2%

	25,600	100.0%	15,383	100.0%

The names of the individual companies have not been disclosed for confidentiality reasons.

17.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 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 $0.5 million is covered by the Canada Deposit Insurance Corporation, the Securities Investor Protection Corporation or the United States Federal Deposit Insurance Corporation, leaving approximately $10.9 million at risk at June 30, 2015 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 June 30, 2015.

All of the Company’s customers have Moody’s Baa or greater ratings and purchase from the Company under contracts for set prices and payment terms.

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Ur-Energy Inc.

Condensed Notes to Unaudited Interim Consolidated Financial Statements

June 30, 2015

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

Liquidity risk (see note 2)

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 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 June 30, 2015, 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 6.5 years, and asset retirement obligations with estimated completion dates until 2033.

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 nominal effect on either the six months ended June 30, 2015 or the six months ended June 30, 2014. 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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Item 2. 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 is 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 MD&A contained in our Annual Report on Form 10-K for the year ended December 31, 2014. The financial statements have been prepared in accordance with US GAAP.

Incorporated on March 22, 2004, Ur-Energy is an exploration stage mining company, as that term is defined in SEC Industry Guide 7. We are engaged in uranium mining, recovery and processing activities, including the acquisition, exploration, development and operation of uraniummineral properties in the United States. We are operating of our first in situ recovery (“ISR”) uranium mine at our Lost Creek Project in Wyoming. 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 wholly-owned subsidiary: Ur-Energy USA Inc, incorporated under the laws of the State of Colorado. Ur-Energy USA has three wholly-owned subsidiaries: NFU Wyoming, LLC, a limited liability company formed under the laws of the State of Wyoming which acts 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 operate our Lost Creek Project and hold our Lost Creek properties and assets; and Pathfinder, incorporated under the laws of the State of Delaware, which holds, among other assets, the Shirley Basin and Lucky Mc properties in Wyoming. Our other U.S. subsidiaries remain unchanged since the filing of our Annual Report on Form 10-K, dated March 2, 2015.

We utilize in situ recovery of the uranium at our flagship project, Lost Creek, and will do so at other projects where possible. The ISR technique is employed in uranium extraction because it allows for an effective recovery of roll front uranium mineralization at a lower cost. At Lost Creek, we extract and process U₃O_8, for shipping to a third-party facility for storage and sales.

Our Lost Creek processing facility, which includes all circuits for the production, drying and packaging of uranium for delivery into sales, is anticipated to process one million pounds of U₃O₈ annually from the Lost Creek mine. The processing facility has the physical design capacity to process two million pounds of U₃O₈ annually, which provides additional capacity to process material from other sources. We expect that the Lost Creek processing facility may be utilized to process captured U₃O₈ from our Shirley Basin Project.

Having completed two additional agreements during the quarter, we currently have eleven U₃O₈sales agreements in place with various U.S. utilities for the sale of U₃O₈ at mid- and long-term contract pricing. The multi-year sales agreements represent a portion of our anticipated production through 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 balance of our Lost Creek production will be sold through spot sales and through additional multi-year agreements.

Changes in Management and Board of Directors

On April 10, 2015, it was announced that the employment agreement with the Company’s President and CEO, Wayne Heili, would end on May 1, 2015 and that Mr. Heili’s employment with the Company would conclude following the completion of that term. Thereafter, Jeffrey T. Klenda formally assumed the role of Acting Chief Executive Officer of Ur-Energy. Mr. Klenda has served as the Chairman of the Board of Directors and

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Executive Director of the Company since 2006. Mr. Heili also resigned from the Board of Directors in May 2015.

At our Annual General and Special Meeting of Shareholders, held May 28, 2015, our shareholders elected all six of the nominated director candidates to our Board, including Gary Huber, PhD, who returns to our Board. Dr. Huber previously served as a director of the Company during 2007.

Mineral Rights and Properties

Ten of our U.S. properties are located in the Great Divide Basin, Wyoming, including Lost Creek. Currently we control a total of more than 2,100 unpatented mining claims and four State of Wyoming mineral leases for a total of approximately 42,000 acres (16,997 hectares) in the area of the Lost Creek Property, including the Lost Creek permit area (the “Lost Creek Project” or “Project”), 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”). Additionally, in the Shirley Basin, Wyoming, our Shirley Basin Project comprises more than 3,500 Company-controlled acres.

The following is a summary of significant activities for the quarter ended June 30, 2015:

Lost Creek Property

During the quarter, Lost Creek achieved the milestone of producing its one millionth pound U₃O₈ since the commencement of operations. Meanwhile, production rates were slowed slightly during parts of the quarter while maintenance continued on various process circuits including the dryers. Overall, captured pounds and production flow rate increased quarter-over-quarter by sourcing from ten header houses in the first mine unit (“MU1”). Header house 10 was brought on line in mid-June. All the initially planned wells in MU1 have been installed and surface construction of the eleventh header house is under way. Plant head grades continue to be significantly higher than originally projected, averaging 108 parts per million this quarter. For the quarter, 207,269 pounds of U₃O₈ were captured within the Lost Creek plant. 183,858 pounds U₃O₈were packaged in drums and 179,672 pounds U₃O₈of drummed inventory were shipped out of the Lost Creek processing plant to the converter.

For the seventh consecutive quarter, Lost Creek Project made sales to meet its contractual commitments and, for the first time, sold 70,000 pounds of U₃O₈ into the spot market in June. Together, contract and spot sales from U3O8 produced at Lost Creek totaled 204,000 pounds at an average price of $31.21 per pound for sales revenues of $6.37 million. The Company also accelerated, from September to April, the delivery of 200,000 pounds at a price of $59.94. To fulfill the delivery, we purchased 200,000 pounds from a trader at the then-current spot price, which generated net cash proceeds of approximately $4.0 million. In total, product sales for the quarter totaled 404,000 pounds at an average sales price of $45.08 per pound. The Results of Operations are detailed further below.

During the quarter, the geology and exploration team completed a mineral resource estimate update for Lost Creek. Due to the assessment of drill hole data obtained from completed wellfield installation within MU1, 2.308 million pounds Measured mineral resource were added to the earlier resource total in MU1 (for a 95% increase to the last reported estimate). Experience gained from the higher uranium recoveries during production operations was also factored into this assessment, resulting in lowering the uranium grade x thickness (GT) cut-off for all uranium intercepts used in the resource estimation from 0.30 to 0.20. GT is defined as the average grade of the intercept times the thickness of the intercept and is a convenient and functional single term used to represent the overall quality of the uranium intercept. An adjustment to the new mineral resource figure was

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then made because of the production of approximately 979,000 pounds of uranium from MU1. All figures are based upon a data obtained through March 31, 2015. After taking into consideration the pounds produced, the current Measured Resource for MU1 increased by 1.329 million pounds to a revised total of 3.757 million pounds, a 55% increase to the last reported MU1 resource in the 2013 Lost Creek PEA.

As well, the analysis completed following the first portion of an exploration drill program conducted immediately south and adjacent to the production area resulted in identification of 121,000 pounds U3O8 in the Measured and Indicated categories of mineral resource and 296,000 pounds Inferred mineral resource (both based upon the lowered GT cutoff). The revised and updated mineral resource estimate became a part of an updated NI 43-101 Technical Report for Lost Creek Property, issued June 17, 2015.

The purpose of the 150-hole exploration drill program is to characterize three previously identified mineralized sand horizons. Thus far, the program has included 91 holes. We anticipate completing the program during third quarter. The results of the further exploration drilling, and a comprehensive update of the mineral resource for the Lost Creek Property based upon the lowered GT cutoff will be included in a further update to the Technical Report anticipated to be completed later this year.

Shirley Basin Project

Following an initial NI 43-101 technical report (August 2014) for Shirley Basin, we commissioned and issued an independent NI 43-101 preliminary economic assessment in January 2015: 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 2014 Shirley Basin technical report was based primarily on analyses of historic drill hole data acquired with the purchase of the property. Additionally, we had drilled 14 confirmation holes prior to the preparation of the report. 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.

Environmental baseline studies are nearing completion on schedule. Data from the studies will be included in the applications for permits and licenses for Shirley Basin, which are currently anticipated to be filed with regulators third quarter of this year.

Results of Operations

U₃O₈ Production and Sales

During the six months ended June 30, 2015, 399,548 pounds of U₃O₈ were captured within the Lost Creek plant. 360,915 of those pounds were packaged in drums and 351,177 pounds of the drummed inventory were shipped to the conversion facility where 350,000 pounds were sold to utility customers. Inventory, production and sales figures for the Lost Creek Project are presented in the following tables. We are presenting the data in the tables for the last four quarters because the nature of our operations is not regularly based on the calendar year. We therefore feel that presenting the last four quarters is a more meaningful representation of operations than comparing comparable periods in the previous year and enables the reader to better interpret trend analysis.

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Inventory and Production	Unit		2015 Q2		2015 Q1		2014 Q4		2014 Q3		2015 YTD

Pounds captured	lb		207,268		192,280		149,564		131,331		399,548
Ad valorem and severance tax	$000	$	310	$	150	$	1,163	$	314	$	460
Wellfield cash cost (1)	$000	$	830	$	1,080	$	881	$	1,012	$	1,909
Wellfield non-cash cost (1)(2)	$000	$	1,333	$	1,335	$	1,350	$	1,350	$	2,668
Ad valorem and severance tax per pound captured	$/lb	$	1.50	$	0.78	$	7.78	$	2.39	$	1.15
Cash cost per pound captured	$/lb	$	4.00	$	5.62	$	5.89	$	7.71	$	4.78
Non-cash cost per pound captured	$/lb	$	6.43	$	6.94	$	9.03	$	10.28	$	6.68

Pounds drummed	lb		183,858		177,057		117,160		125,915		360,915
Plant cash cost (3)	$000	$	1,983	$	1,718	$	1,553	$	1,704	$	3,702
Plant non-cash cost (2)(3)	$000	$	498	$	497	$	507	$	504	$	995
Cash cost per pound drummed	$/lb	$	10.79	$	9.70	$	13.26	$	13.53	$	10.26
Non-cash cost per pound drummed	$/lb	$	2.71	$	2.81	$	4.33	$	4.00	$	2.76

Pounds shipped to coversion facility	lb		179,672		171,505		102,071		126,499		351,177
Distribution cash cost (4)	$000	$	141	$	145	$	112	$	(31)	$	286
Cash cost per pound shipped	$/lb	$	0.78	$	0.85	$	1.10	$	(0.25)	$	0.81

Pounds purchased	lb		200,000		-		-		-		200,000
Purchase costs	$000	$	7,878	$	-	$	-	$	-	$	7,878
Cash cost per pound purchased	$/lb	$	39.39	$	-	$	-	$	-	$	39.39

Notes:

Wellfield costs include all wellfield operating costs plus amortization of the related mineral property acquisition costs and depreciation of the related asset retirement obligation 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.

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

Plant costs include all plant operating costs, site overhead costs and depreciation of the related plant construction and asset retirement obligation costs.

⁴

Distribution 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 per pound have generally declined throughout the past four quarters. In November 2014, the State of Wyoming retroactively increased the ad valorem and severance tax industry factor used in calculating the taxable value of the extracted uranium by 31%. The one-time retroactive adjustment to the tax expense was reflected in Q4 2014 resulting in significantly higher costs per pound in that quarter. In March 2015, the State revised the industry factor increase down to a six percent increase, as compared to the previously announced 31% increase, after further review of operational data submitted by the affected companies. The revision resulted in a substantially lower cost per pound than what had been reflected the previous quarter. In 2015 Q2, the ad valorem and severance cost per pound returned to more traditional levels.

Our wellfield cash costs decreased in 2015 Q2 primarily due to lower labor costs during the quarter. Together with an increase in pounds captured, the cash cost per pound captured decreased to $4.00 per pound in 2015 Q2.

Plant cash costs increased in 2015 Q2 primarily due to a $0.2 million one-off, road maintenance charge from Sweetwater County related to the Crook’s Gap road. The Company had agreed to pay 10% of the cost to re-

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condition the road, which is one of several roads used to access the facility, and the 2015 Q2 charge completes the Company’s portion of the requirement. Pounds drummed within the plant did increase during the quarter, although we fell short of our projected target of 210,000 pounds. During the quarter, we took our dryers down for maintenance, which lowered our ability to dry and drum pounds during late May and early June. July rates have returned to normal levels and as at July 30,2015, 81,100 pounds have been drummed during the month. Although pounds drummed did increase during the quarter, our cash cost per pound drummed increased to $10.79, primarily due to the inclusion of the one-off, road maintenance charge.

Distribution costs were consistent during the quarter and the cost per pound shipped decreased to $0.78.

Non-cash costs are relatively fixed and the resulting non-cash cost per pound will fluctuate with production. During the quarter, non-cash costs per pound decreased as pounds captured, drummed and shipped all increased.

To satisfy a term contractual delivery, we purchased 200,000 pounds on the open market at a cost of $39.39 per pound. The cost reflected the spot price in effect at the time.

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Sales and cost of sales	Unit		2015 Q2		2015 Q1		2014 Q4		2014 Q3		2015 YTD

Pounds sold	lb		404,000		146,000		100,000		100,000		550,000
U3O8 sales	$000	$	18,213	$	7,380	$	6,603	$	5,996	$	25,593
Average long-term contract price	$/lb	$	46.88	$	50.55	$	66.03	$	59.96	$	48.00
Average spot price (1)	$/lb	$	36.50	$	-	$	-	$	-	$	36.50
Average price per pound sold	$/lb	$	45.08	$	50.55	$	66.03	$	59.96	$	46.53

U3O8 cost of sales (2)	$000	$	13,791	$	5,390	$	3,700	$	3,752	$	19,178
Ad valorem and severance tax cost per pound sold	$/lb	$	2.78	$	4.73	$	3.18	$	2.52	$	3.60
Cash cost per pound sold	$/lb	$	16.15	$	18.86	$	20.32	$	20.77	$	17.28
Non-cash cost per pound sold	$/lb	$	10.05	$	13.32	$	13.47	$	14.23	$	11.41
Cost per pound sold - produced	$/lb	$	28.98	$	36.91	$	36.97	$	37.52	$	32.29
Cost per pound sold - purchased	$/lb	$	39.39	$	-	$	-	$	-	$	39.39
Average cost per pound sold	$/lb	$	34.14	$	36.91	$	36.97	$	37.52	$	34.87

U3O8 gross profit	$000	$	4,422	$	1,990	$	2,903	$	2,244	$	6,415
Gross profit per pound sold	$/lb	$	10.94	$	13.63	$	29.03	$	22.44	$	11.66
Gross profit margin	%		24.3%		27.0%		44.0%		37.4%		25.1%

Ending Inventory Balances
Pounds
In-process inventory	lb		79,036		79,284		65,233		66,298
Plant inventory	lb		30,006		25,819		15,188		5,634
Conversion facility inventory	lb		66,314		82,021		56,259		47,506
Total inventory	lb		175,356		187,124		136,680		119,438

Total cost
In-process inventory	$000	$	1,219	$	1,368	$	2,084	$	1,394
Plant inventory	$000	$	850	$	761	$	882	$	180
Conversion facility inventory	$000	$	1,815	$	2,573	$	2,202	$	1,727
Total inventory	$000	$	3,884	$	4,702	$	5,168	$	3,301

Cost per pound
In-process inventory	$/lb	$	15.42	$	17.25	$	31.95	$	21.03
Plant inventory	$/lb	$	28.33	$	29.47	$	58.07	$	31.95
Conversion facility inventory	$/lb	$	27.37	$	31.37	$	39.14	$	36.35

Notes:

There were no spot sales in either 2015 Q1 or 2014.

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

U₃O₈ sales of $ 18.2 million for 2015 Q2 were based on selling 404,000 pounds at an average price of $45.08. During the quarter, we accelerated a 200,000 pound contractual delivery requirement from September to April, which we filled with the purchase of U₃O₈from the spot market, we met our other regularly scheduled contract deliveries totaling 134,000 pounds and we also sold 70,000 pounds on the spot market.

For the quarter, our cost of sales totaled $13.8 million based on selling 204,000 pounds from production at a total cost per pound of $28.98, down from $36.92 in the previouse quarter, and 200,000 pounds from purchases at a total cost per pound of $39.39. As discussed above, our production costs per pound have generally been

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decreasing and the resulting cost per pound sold has benefited from this as well. During the quarter, our cash cost per pound sold decreased from $18.86 per pound to $16.15 per pound. We expect this trend to continue so long as our production levels continue to rise and our cash costs remain consistent.

At the end of the quarter, the average cash cost per pound in the conversion facility ending inventory was $15.48, down from $16.73 at the end of the previous quarter.

The gross profit for the quarter was $4.4 million, which represents a gross profit margin of approximately 24%. This was lower than the previous two quarters primarily due to the lower average sales price received per pound in 2015 Q2. One contract, in particular, had been established at a time when lower uranium prices were in place. Overall, the average sales price for the Company’s 2015 contracts is approximately $50 per pound. During the quarter, we also conducted our first spot sale at a price of $36.50 per pound, which contributed to the lower average sales price for the quarter.

US GAAP Reconciliations

Cash cost per pound and non-cash cost per pound for produced and sold U₃O₈presented in the above tables are non-US GAAP measures. These measures do not have a standardized meaning or a consistent basis of calculation under US GAAP. These measures are used to assess business performance and may be used by certain investors to evaluate 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	2015 Q2		2015 Q1			2014 Q4		2014 Q3	2015 YTD

Sales per financial statements	$000	$	18,213	$	7,387	$	6,638	$	7,330	$	25,600
Less disposal fees	$000	$	-	$	(7)	$	(35)	$	(80)	$	(7)
Less gain from sale of deliveries under contract	$000	$	-	$	-	$	-	$	(1,254)	$	-
U₃O₈ sales	$000	$	18,213	$	7,380	$	6,603	$	5,996	$	25,593

Pounds sold - produced	lb		204,000		146,000		100,000		100,000		350,000
Pounds sold - purchased	lb		200,000		-		-		-		200,000
Total pounds sold	lb		404,000		146,000		100,000		100,000		550,000

Average price per pound sold	$/lb	$	45.08	$	50.55	$	66.03	$	59.96	$	46.53

2014 Q3 does not include $1.2 million recognized from the gain on assignment of deliveries under long-term contracts because the additional revenue would distort the average price per pound sold (see the Sales footnotes to the financial statements for the period ended September 30, 2014).

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 instructions for a title transfer to the customer. Revenue is recognized once a title transfer of the U₃O₈ is confirmed by the conversion facitlity.

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Total Cost Per Pound Sold Reconciliation	Unit		2015 Q2		2015 Q1		2014 Q4		2014 Q3		2015 YTD

Ad valorem & severance taxes	$000	$	310	$	150	$	1,163	$	314	$	460
Wellfield costs	$000	$	2,163	$	2,415	$	2,230	$	2,361	$	4,577
Plant and site costs	$000	$	2,481	$	2,215	$	2,060	$	2,207	$	4,696
Distribution costs	$000	$	141	$	145	$	112	$	(31)	$	286
Inventory change	$000	$	818	$	465	$	(1,868)	$	(1,099)	$	1,283
Cost of sales - produced	$000	$	5,913	$	5,390	$	3,697	$	3,752	$	11,302
Cost of sales - purchased	$000	$	7,878	$	—	$	—	$	—	$	7,878
Total cost of sales	$000	$	13,791	$	5,390	$	3,697	$	3,752	$	19,180

Pounds sold produced	lb		204,000		146,000		100,000		100,000		350,000
Pounds sold purchased	lb		200,000		—		—		—		200,000
Total pounds sold	lb		404,000		146,000		100,000		100,000		550,000

Average cost per pound sold - produced (1)	$/lb.	$	28.99	$	36.91	$	36.97	$	37.52	$	32.29
Average cost per pound sold - purchased	$/lb.	$	39.39	$	-	$	-	$	-	$	39.39
Total average cost per pound sold	$/lb.	$	34.14	$	36.91	$	36.97	$	37.52	$	34.87

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 inventory, production and sales 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 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.

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Three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014

The following tables summarizes the results of operations for the six months ended June 30, 2015 and 2014 (in thousands of U.S. dollars):


	Three months ended June 30,
	2015	2014
	$	$
Sales (1)	18,213	9,236
Cost of sales	(13,799)	(7,169)
Gross profit	4,414	2,067
Exploration and evaluation expense	(550)	(854)
Development expense	(557)	(711)
General and administrative expense	(1,735)	(1,335)
Accretion	(128)	(39)
Write-off of mineral properties	-	(93)
Net profit (loss) from operations	1,444	(965)
Interest income (Expense) (net)	(658)	(675)
Warrant mark to market gain	248	839
Loss from equity investment	(5)	(3)
Foreign exchange gain (loss)	(4)	-
Net profit (loss)	1,025	(804)

Profit (loss) per share – basic and diluted	0.01	(0.01)

Revenue per pound sold	45.08	34.64

Total cost per pound sold	34.14	30.96

Gross profit per pound sold	10.94	3.68

^1.

Effective June 30, 2014, we stopped treating those taxes as a reduction in sales revenues, but rather as a cost of sales as the taxes are based on pounds extracted, not sold. Sales and cost of sales the the quarter ended June 30, 2014 were therefore increased by $736 thousand to reflect the change in treatment from the first quarter of 2014 and the fourth quarter of 2013.

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	Six months ended June 30,
	2015	2014
	$	$

Sales (1)	25,600	15,383
Cost of sales	(19,189)	(10,409)
Gross profit	6,411	4,974
Exploration and evaluation expense	(1,235)	(1,872)
Development expense	(1,586)	(1,285)
General and administrative expense	(3,252)	(3,647)
Accretion expense	(254)	(77)
Write-off of mineral properties	-	(93)
Net profit (loss) from operations	84	(2,000)
Interest income (expense) (net)	(1,346)	(1,311)
Warrant mark to market gain	171	576
Loss from equity investment	(5)	(3)
Foreign exchange loss	(3)	(14)
Net loss	(1,099)	(2,752)

Loss per share – basic and diluted	(0.01)	(0.02)

Revenue per pound sold	46.53	43.81

Total cost per pound sold	34.87	32.75

Gross profit per pound sold	11.66	11.06

^1.

Effective June 30, 2014, we stopped treating those taxes as a reduction in sales revenues, but rather as a cost of sales as the taxes are based on pounds extracted, not sold. Sales and cost of sales the the six months ended June 30, 2014 were therefore increased by $682 thousand to reflect the change in treatment from the fourth quarter of 2013.

Sales

We sold a total of 404,000 and 550,000 pounds of U₃O₈ during the three and six months ended June 30, 2015 for an average price of $45.08 and $46.53 per pound, respectively, as compared to the same periods in 2014 when we sold 207,760 and 317,760 pounds for average prices of $34.64 and $43.81. The fluctuation in sales prices relates primarily to the contractual delivery commitments.

We recognized no external disposal fees at the Shirley Basin site in the quarter. For the six months we recognized $7 thousand compared to $49 throusand and $209 thousand from disposal fees during the three and six months ended June 30, 2014, respectively.

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

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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.

The costs included in cost of sales for our produced inventory were as projected and our cost per pound sold generally declined during the quarter as compared to previous quarters. This was primarily because our production was higher while our costs, which are primarily process based, do not fluctuate in proportion to the product produced. As production levels increase, the costs per pound sold will decrease so long as production costs remain on target.

Our cost per pound sold for produced inventory, decreased $5.24 to $28.98 from $34.22 for the quarter and by $1.56 from $33.85 to $32.29 for the six month period. This is primarily a function of increased production. 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.

During April 2015, we determined that accelerating a high priced contract delivery and fulfilling it with purchased inventory was a good strategic move for the Company to pursue. We purchased inventory to cover the sale on the spot market for $39.39 which was substantially above our cash cost of production, but well below the contracted sales price per pound. As we did not (nor will we in the future) purchase U₃O₈ to hold as inventory, this cost was passed directly to cost of goods sold where it is included in our average cost per pound sold calculations, but not in our inventory valuation calculations. As a result, our average cost of sales per pound was increased to $34.14 for the quarter and $34.87 for the six months ended June 30, 2015.

Gross Profit

The gross profit was $4.4 million and $6.4 million for the three and six months ended June 30, 2015, respectively, which represents gross profit margins of approximately 24% and 25% as compared to $2.0 million and $4.9 million in the respective periods in 2014, which represented gross profit margins of approximately 1% and 23%, respectively. Gross profit per pound sold increased to $10.94 in 2015 Q2 from $3.68 in 2014 Q2. For the six month period, gross profit per pound increased $0.60 to $11.66 from $11.06 in 2014. The primary reason for the significant fluctuation in gross profit is the contractual sales prices of the contracts delivered into for the period. The quarter on quarter fluctuation is due to the timing of the deliveries into various contracts with different pricing points.

Operating Expenses

Total operating expenses for the three and six months ended June 30, 2015 were $3.0 million and $6.3 million, respectively. Operating expenses includes exploration and evaluation expense, development expense, G&A expense and mineral property write-offs. These expenses decreased by $0.2 million and $0.8 million, respectively, compared to the same periods in 2014 due primarily to decreases in labor costs related to bonuses and a potential severance liability that was recorded in 2014.

Exploration and evaluation expense consists of labor and 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 $0.3 million and $0.6 million for the three and six months ended June 30, 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 declined due to a reduction in labor related expenses of $0.1 million and

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$0.3 million for the three and six month periods and land lease costs associated with the Mustang property which was abandoned in January 2014.

Development expense includes costs incurred at the Lost Creek Project not directly attributable to production activities, including wellfield construction, drilling and development costs. It also includes costs associated with the Shirley Basin and Lucky Mc properties as they are in a more advanced stage. Development expenses decreased by $0.2 million and increased by $0.3 million in the three and six months ended June 30, 2015 compared to 2014, respectively. The increase was primarily related to the timing of drilling expense from programs in the Lost Creek project area.

G&A expense relates to administration, finance, investor relations, land and legal functions and consists principally of personnel, facility and support costs. Expenses increased by $0.4 million and decreased by $0.8 million for the three and six months ended June 30, 2015 compared to 2014. The 2015 year-to-date decrease is mainly related to lower labor related expenses for bonuses and accruals incurred in the first quarter of 2015 as compared to 2014, which were offset to a limited degree by additional labor accruals in the second quarter of 2015 related to the changes in management discussed above.

Other Income and Expenses

Net interest expense increased for the six months ended June 30, 2015 due to increased borrowing during 2014, but declined in the three months of 2015 compared to 2014 due to principal reduction payments.

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 capital stock, these warrants are considered a derivative and are therefore treated as a liability. The gains declined by $0.6 million and $0.4 million for the three and six months ended June 30, 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.

Profit (Loss) per Common Share

The basic and diluted gain (loss) per common share for the three and six months ended June 30, 2015 were a gain of $0.01 and a loss of $0.01, respectively compared to losses of $0.01 and $0.02 in the respective periods 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.

Liquidity and Capital Resources

As of June 30, 2015, we had cash resources, consisting of cash and cash equivalents of $3.8 million, an increase of $0.7 million from the December 31, 2014 balance of $3.1 million. The cash resources consist of Canadian and U.S. dollar denominated deposit accounts and money market funds. We generated $4.1 million from operating activities during the six months ended June 30, 2015. During the same period, we used less than $0.1 million for investing activities and $3.4 million for financing activities.

Prior to the commencement of U₃O₈ deliveries and corresponding sales, we financed our operations primarily through the issuance of equity securities and debt instruments. Initial deliveries and product sales commenced in December 2013 although the first collections under those sales did not occur until January 2014. The Company will continue to consider additional financing opportunities until it builds sufficient cash reserves to

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cover the variability of cash receipts that result from a limited number of large sales annually which is typical in this industry.

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”). Prior to closing the State Bond Loan, we had previously obtained interim financing from RMBAH which had been paid off from the proceeds of the State Bond Loan. On December 19, 2013, we redrew $5.0 million from the RMBAH loan facility. We subsequently renegotiated the loan amount to $6.5 million together with an additional line of credit of $3.5 million. The RMBAH 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 8.76% in total) plus eight equal quarterly principal payments which commenced June 30, 2014. As of June 30, 2015, the outstanding balance on the loan is $2.44 million while the balance on the line is $3.5 million. The line of credit is due quarterly, but may be immediately redrawn until March 31, 2016 when it is due in full. The RMBAH loan facility is secured by all of the assets of Pathfinder.

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 October 1, 2021. The State Bond Loan is secured by all of the assets at the Lost Creek Project.

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. As at July 30, 2015, we have not sold any securities under the shelf registration statement.

We had an operating gain of $0.1 million after deducting total operating expenses of $6.4 million (discussed below) for the six months ended June 30, 2015. After recording interest and other expenses, the net loss for that period was $1.1 million.

During March 2015, the WDEQ approved the Shirley Basin and Lucky Mc bonding totaling $12.7 million. The NRC has yet to approve the bonding. While this represents a slight increase over what was submitted to the WDEQ in 2014, we have not modified our surety bonding levels as of June 30, 2015.

Collections for the six months from U₃O₈ sales totaled $25.6 million.

Operating activities generated $4.1 million during the six months ended June 30, 2015 as compared to using $1.0 million during the same period in 2014. Inventory decreased by $1.3 million due to lower costs per pound which were associated in large part to the changes in the Wyoming severance and ad valorem industry factors as discussed previously, but also a decrease in our cash and non-cash costs per pound due to higher production levels. In addition, there were outstanding uranium sales receivable at December 31, 2013 which were collected in the six months ended June 30, 2014

During the first six months of 2015, the Company invested less than $0.1 million in equipment.

During the first six months of 2015, the Company used $3.2 million for financing activities, primarily for principal payments totaling $3.6 million on the RMBAH and Sweetwater debt, offset by $0.4 million from the exercise of stock options by current and former employees and directors.

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Liquidity Outlook

Based upon our current capital balance and the expected timing of product sales, we believe we will be able to meet current obligations without additional funding. Additional cash may be required for the construction and development of our Shirley Basin Project, but no budget or timetable has been established for that project pending the submission of permit and license applications, which are currently being prepared.

We expect that any major capital projects will be funded by operating cash flow, cash on hand or additional financing as required. If these cash sources 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, however, we may issue additional debt or equity securities at any time.

Looking ahead

The average spot price per pound of U₃O₈, as reported by Ux Consulting Company, LLC and TradeTech, LLC, for the week of July 30, 2015 was $36.00. As a result of the continuing low spot price environment, we will continue to maintain production at levels that will be consistent with our contractual sales obligations, which are 630,000 pounds at an average realizable price of $49.49 per pound in 2015.

Our current production plan for 2015 is still to maintain an average production rate of approximately 70,000 pounds per month and produce between 750,000 and 850,000 pounds of U₃O₈. Excess production will be used to build inventory, which may be utilized to complete additional discretionary spot sales transactions on an as-needed basis if market conditions warrant.

During the six months ended June 30, 2015, we sold 550,000 pounds of U₃O₈ at an average price per pound of $46.53. Our gross margin per pound sold during the period was $11.66, or approximately 25%. As projected, our gross margin in 2015 Q2 of 24% was slightly less than the 27% gross margin in 2015 Q1 due to delivering into a lower priced contract during the period. We expect slightly better margins for the year 2015 as we fulfilled approximately 80% of our lowest priced contractual delivery contract in 2015 Q2.


Ending Conversion Facility Inventory Cost Per Pound Summary	Unit	June 30, 2015

Ad valorem and severance tax cost per pound	$/lb	$	2.30
Cash cost per pound	$/lb	$	15.48
Non-cash cost per pound	$/lb	$	9.59
Total cost per pound	$/lb	$	27.37

As at July 30, 2015, our unrestricted cash position was $3.6 million. Given our current cash resources, contracted sales positions and low cash costs per pound, we do not anticipate the need for additional funding in 2015 unless it is advantageous to do so.

Transactions with Related Parties

We did not participate in any material transactions with related parties during the period ended June 30, 2015.

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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. Timely disclosure of such transactions is made as soon as reportable events arise.

Critical Accounting Policies and Estimates

We have established the existence of uranium resources at the Lost Creek Property, 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. Accordingly, we have adopted an accounting policy with respect to the nature of items that qualify for capitalization for in situ U₃O₈ mining operations to align our policy to the accounting treatment that has been established as best practice for these types of mining operations.

The development of the wellfield includes production and monitor well drilling and completion, piping within the wellfield and to the processing facility, header houses used to monitor production and disposal wells associated with the operation of the mine. These costs are expensed when incurred.

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 June 30, 2015, the average current spot and long term price of U₃O₈ was $36.38 and $46.00, respectively. This compares to prices of $35.50 and $50.00 as of December 31, 2014. Management did not identify any impairment indicators for any of the Company’s mineral properties during the six months ended June 30, 2015.

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.

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Capital assets

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 for other uses for the equipment 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.

Share-Based Expense

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.

New accounting pronouncements

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is effective for fiscal periods beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. We have elected early adoption of this standard effective with these financial statements. The impact was to move $174 thousand from current deferred loan costs to offset the current portion of the long term debt and to move $638 thousand of deferred loan costs previously included in non-current assets to offset the long term portion of the notes payable as of June 30, 2015. As at December 31, 2014, we moved $190 thousand of current deferred cost to offset the current portion of long-term debt and $716 thousand of non-current deferred loan costs to offset non-current notes payable.

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.

Outstanding Share Data

The “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes information available to July 30, 2015. As of July 30, 2015, we had outstanding 130,048,326 common shares and 7,959,124 options to acquire common shares.

Item 3. 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 U.S. dollar is now the functional currency of U.S. operations, the currency risk has been significantly reduced.

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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 U₃O₈. We have eleven U₃O₈ 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 U₃O₈ price fluctuations. Historically, U₃O₈ prices have been subject to fluctuation, and the price of U₃O₈ 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 U₃O₈ producing and consuming countries and production levels and costs of production of other producing companies. The spot market price for U₃O₈ 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 $36.00 per pound as of July 30, 2015.

Item 4. Controls and Procedures

(a)Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this MD&A, 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) Changes in Internal Controls over Financial Reporting

No changes in our internal control over financial reporting occurred during the six months ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

Item 1. LEGAL PROCEEDINGS

No new legal proceedings or material developments in pending proceedings.

Item 1A. RISK FACTORS

There have been no material changes for the six months ended June 30, 2015 from those risk factors set forth in our Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3. Defaults upon Senior Securities

None

Item 4. MINE SAFETY DISCLOSURE

Our operations and exploration activities at Lost Creek are not subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977.

Item 5. Other Information

None

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Item 6. Exhibits


		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Date of Report	Exhibit	Filed Herewith

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

In accordance with Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, is deemed not filed for purposes of section 18 of the Exchange Act, and otherwise is not subject to liability under these sections.

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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: July 31, 2015	By:	/s/ Jeffrey T. Klenda
		Jeffrey T. Klenda
		Acting Chief Executive Officer
		(Principal Executive Officer)


Date: July 31, 2015	By:	/s/ Roger L. Smith
		Roger L. Smith
		Chief Financial Officer
		(Principal Financial Officer and
		Principal Accounting Officer)