EX-99.2 3 d30993dex992.htm EXHIBIT 99.2

Exhibit 99.2

Exhibit 99.2

Management’s discussion and analysis

for the quarter ended June 30, 2015

SECOND QUARTER UPDATE			4
CONSOLIDATED FINANCIAL RESULTS			8
OUTLOOK FOR 2015			15
LIQUIDITY AND CAPITAL RESOURCES			17
FINANCIAL RESULTS BY SEGMENT
URANIUM			19
FUEL SERVICES			21
NUKEM			21
OUR OPERATIONS
URANIUM 2015 Q2 UPDATES			22
FUEL SERVICES 2015 Q2 UPDATES			24
QUALIFIED PERSONS			24
ADDITIONAL INFORMATION			25

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited condensed consolidated interim financial statements and notes for the quarter ended June 30, 2015 (interim financial statements). The information is based on what we knew as of July 29, 2015 and updates our first quarter and annual MD&A included in our 2014 annual report.

As you review this MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2014 and annual MD&A. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.

The financial information in this MD&A and in our financial statements and notes are prepared according to International Financial Reporting Standards (IFRS), unless otherwise indicated.

Unless we have specified otherwise, all dollar amounts are in Canadian dollars.

Throughout this document, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries, including NUKEM Energy Gmbh (NUKEM), unless otherwise indicated.

Caution about forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans, future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A as forward-looking information.

Key things to understand about the forward-looking information in this MD&A:

• It typically includes words and phrases about the future, such as: anticipate, believe, estimate, expect, plan, will, intend, goal, target, forecast, project, strategy and outlook (see examples below).

• It represents our current views, and can change significantly.

• It is based on a number of material assumptions, including those we have listed on page 3, which may prove to be incorrect.

• Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks on pages 2 and 3. We recommend you also review our annual information form, first quarter MD&A, and annual MD&A, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

• Forward-looking information is designed to help you understand management’s current views of our near and longer term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

Examples of forward-looking information in this MD&A

• the discussion under the heading Our strategy

• our expectations about 2015 and future global uranium supply and demand and number of reactors including the discussion under the heading Uranium market update

• the discussion of our expectations relating to our transfer pricing disputes including our estimate of the amount and timing of expected cash taxes and transfer pricing penalties

• our consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2015

• our expectations for uranium deliveries in the third quarter and for the balance of 2015

• our price sensitivity analysis for our uranium segment

• our expectation that existing cash balances and operating cash flows will meet our anticipated 2015 capital requirements without the need for any significant additional funding

• our expectation that our operating and investment activities for the remainder of 2015 will not be constrained by the financial-related covenants in our unsecured revolving credit facility

• our future plans and expectations for each of our uranium operating properties and fuel services operating sites

Material risks

• actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor

• we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates

• our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms

• our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate

• we are unable to enforce our legal rights under our existing agreements, permits or licences

• we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our disputes with tax authorities

• we are unsuccessful in our dispute with CRA and this results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision

• there are defects in, or challenges to, title to our properties

• our mineral reserve and resource estimates are not reliable, or we face unexpected or challenging geological, hydrological or mining conditions

• we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays

• we cannot obtain or maintain necessary permits or approvals from government authorities

• we are affected by political risks

• we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy

• we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium

• there are changes to government regulations or policies that adversely affect us, including tax and trade laws and policies

• our uranium suppliers fail to fulfil delivery commitments

• our McArthur River development, mining or production plans are delayed or do not succeed for any reason

• our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties with the jet boring mining method or freezing the deposit to meet production targets, or any difficulties with the McClean Lake mill modifications or expansion or milling of Cigar Lake ore

• we are unable to obtain an extension to the term of Inkai’s block 3 exploration licence

• we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes

2    CAMECO CORPORATION

• our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

Material assumptions

• our expectations regarding sales and purchase volumes and prices for uranium and fuel services

• our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants

• our expected production level and production costs

• the assumptions regarding market conditions upon which we have based our capital expenditures expectations

• our expectations regarding spot prices and realized prices for uranium, and other factors discussed under the heading Price sensitivity analysis: uranium segment

• our expectations regarding tax rates and payments, foreign currency exchange rates and interest rates

• our expectations about the outcome of disputes with tax authorities

• our decommissioning and reclamation expenses

• our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable

• the geological, hydrological and other conditions at our mines

• our McArthur River development, mining and production plans succeed

• our Cigar Lake development, mining and production plans succeed, the jet boring mining method works as anticipated, and the deposit freezes as planned

• modification and expansion of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected

• the term of Inkai’s block 3 exploration licence is extended

• our ability to continue to supply our products and services in the expected quantities and at the expected times

• our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals

• our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

2015 SECOND QUARTER REPORT    3

Our strategy

We are a pure-play nuclear fuel supplier, focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. Our strategy is to profitably produce at a pace aligned with market signals in order to increase long-term shareholder value, and to do that with a focus on safety, people and the environment.

We plan to:

• ensure continued reliable, low-cost production from our flagship operation, McArthur River/Key Lake, and seek to expand that production

• ensure continued reliable, low-cost production at Inkai

• successfully ramp up production at Cigar Lake

• manage the rest of our production facilities and other sources of supply in a manner that retains the flexibility to respond to market signals and take advantage of value adding opportunities within our own portfolio and the uranium market

• maintain our low-cost advantage by focusing on execution and operational excellence

You can read more about our strategy in our 2014 annual MD&A.

Second quarter update

On January 31, 2014, we announced the sale of our 31.6% limited partnership interest in Bruce Power Limited Partnership (BPLP) and related entities for $450 million. The sale closed on March 27, 2014 and was accounted for as being completed effective January 1, 2014.

Under IFRS, we are required to report the results from discontinued operations separately from continuing operations. We have included the financial impact of the sale of BPLP in discontinued operations.

Throughout this document, for comparison purposes, all results for “earnings from continuing operations” and “cash from continuing operations” have been revised to exclude BPLP. The impact of BPLP is shown separately as a discontinued operation.

Our performance

HIGHLIGHTS		THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
($ MILLIONS EXCEPT WHERE INDICATED)		2015				2014				CHANGE				2015				2014				CHANGE
Revenue			565				502				13	%			1,130				921				23	%
Gross profit			153				136				13	%			282				243				16	%
Net earnings attributable to equity holders			88				127				(31	)%			79				259				(69	)%
$ per common share (diluted)			0.22				0.32				(31	)%			0.20				0.65				(69	)%
Adjusted net earnings (non-IFRS, see page 9)			46				79				(42	)%			115				115				—
$ per common share (adjusted and diluted)			0.12				0.20				(40	)%			0.29				0.29				—
Cash provided by (used in) operations (after working capital changes)			(65	)			(25	)			(160	)%			68				(18	)			478	%

SECOND QUARTER

Net earnings attributed to equity holders this quarter were $88 million ($0.22 per share diluted) compared to net earnings of $127 million ($0.32 per share diluted) in the second quarter of 2014. In addition to the items noted below, our net earnings were affected by mark-to-market gains on foreign exchange derivatives.

On an adjusted basis, our earnings this quarter were $46 million ($0.12 per share diluted) compared to $79 million ($0.20 per share diluted) (non-IFRS measure, see page 9) in the second quarter of 2014. The change was mainly due to:

• higher administrative costs

• a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014

4    CAMECO CORPORATION

partially offset by:

• higher gross profit from uranium and fuel services segments

• settlement costs of $12 million with respect to the early redemption our Series C debentures recorded during the second quarter of 2014

See Financial results by segment on page 19 for more detailed discussion.

FIRST SIX MONTHS

Net earnings in the first six months of the year were $79 million ($0.20 per share diluted) compared to $259 million ($0.65 per share diluted) in the first six months of 2014. In addition to the items noted below, our net earnings were affected by mark-to-market losses on foreign exchange derivatives. Our 2014 earnings also included a gain on the sale of our interest in BPLP of $127 million.

On an adjusted basis, our earnings for the first six months of this year were $115 million ($0.29 per share diluted) (non-IFRS measure, see page 9) unchanged from the first six months of 2014. Key variances include:

• higher administration costs

• a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014

• lower tax recovery

partially offset by:

• higher gross profit from our uranium, fuel services and NUKEM segments

• lower losses from equity accounted investments

Our 2014 adjusted net earnings were also impacted by:

• an early termination fee of $18 million incurred in 2014 as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd. (SFL), which was to expire in 2016

• settlement costs of $12 million with respect to the early redemption our Series C debentures recorded in 2014

See Financial results by segment on page 19 for more detailed discussion.

Operations update

						THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
HIGHLIGHTS						2015				2014				CHANGE				2015				2014				CHANGE
Uranium		Production volume (million lbs)					5.4				4.0				35	%			10.5				9.7				8	%
		Sales volume (million lbs)1					7.3				7.4				(1	)%			14.3				14.3				—
		Average realized price		($US/lb)			46.57				45.93				1	%			45.03				46.26				(3	)%
				($Cdn/lb)			58.04				50.76				14	%			55.45				50.67				9	%
		Revenue ($millions)1					424				376				13	%			791				724				9	%
		Gross profit ($millions)					127				110				15	%			240				229				5	%
Fuel services		Production volume (million kgU)					3.1				3.8				(18	)%			5.7				7.8				(27	)%
		Sales volume (million kgU)					2.4				3.3				(27	)%			5.4				5.1				6	%
		Average realized price		($Cdn/kgU)			29.70				21.28				40	%			25.45				21.68				17	%
		Revenue ($millions)					70				70				—				136				110				24	%
		Gross profit ($millions)					19				16				19	%			27				18				50	%
NUKEM		Uranium sales (million lbs)1					1.5				1.5				—				4.0				2.2				82	%
		Average realized price		($Cdn/lb)			50.47				41.63				21	%			42.80				41.01				4	%
		Revenue ($millions)1					81				62				31	%			178				94				89	%
		Gross profit ($millions)					11				13				(15	)%			22				10				120	%

¹  Includes sales and revenue between our uranium, fuel services and NUKEM segments. Please see Financial results by segment beginning on page 19.

Production in our uranium segment this quarter was 35% higher compared to the second quarter of 2014, mainly due to production from Cigar Lake and higher production from McArthur River/Key Lake partially offset by lower production at Rabbit Lake, Inkai, and our US operations. See Uranium 2015 Q2 updates starting on page 22 for more information.

2015 SECOND QUARTER REPORT    5

Production in our fuel services segment was 18% lower this quarter than in the second quarter of 2014 due to lower planned annual production in 2015.

Key highlights:

• Forest fire risk across northern Saskatchewan has diminished and all evacuees have now been allowed to return home, although we continue to monitor the situation closely. Air and road access to our operations has improved and we have resumed normal shipping of packaged product from our operations. We still expect to meet our 2015 production and sales targets.

• At Cigar Lake, the jet boring system (JBS) continued to perform as expected. During the first half of the year, we successfully mined 4.8 million pounds of uranium for shipment to the McClean Lake mill, which, during the second quarter, packaged approximately 2.4 million pounds (100% basis, 1.2 million pounds our share).

• At McArthur River, the CNSC and the province of Saskatchewan have approved an increase of our licence production limit to 25 million pounds per year (100% basis), which matches the annual mill production licence limit at Key Lake. The increased production limit aligns with our strategy to maintain the flexibility to adjust to market conditions.

Also of note:

Ken Seitz, our senior vice-president and chief commercial officer is resigning effective August 15, 2015, to take a chief executive officer position with a company outside the nuclear industry. Mr. Seitz had oversight for our marketing, corporate development, and exploration activities. At this time, the plan is to reallocate these activities, and his other responsibilities, among members of our officer team. This re-allocation will be finalized in September 2015.

Uranium market update

The market continued to be flat in the second quarter, with spot prices remaining in the mid-$30s (US). The quantity transacted in the spot market was at normal levels, though no significant price trends emerged. We believe this flat environment is simply a function of the currently over-supplied market, where we believe participants’ uncovered requirements start to open up in the next two to three years. There were supply disruptions in the first half of 2015 that reduced the over-supply situation, but the reductions did not result in any notable change in spot or term demand from utilities.

Japan restarts remain the most important driver of market sentiment in the short term. While the market has been disappointed with ongoing delays, the first reactor restarts appear to be imminent with Kyushu having loaded fuel into Sendai unit 1 for anticipated restart in August, while preparing Sendai unit 2 for restart this fall. We remain confident that a significant number of units will be restarted in Japan over time, though the regulatory approval process and restart schedules are clearly hard to predict.

Beyond these short-term challenges in the market, longer term, strong fundamentals underpin a positive outlook for the industry. Globally, there are 64 reactors currently under construction, with a net increase of 82 reactors expected over the next 10 years. China continues to execute on its remarkable nuclear growth plan, with 26 reactors operating and 24 under construction. India continues to demonstrate confidence in its nuclear growth strategy, evidenced by the signing of new long-term uranium supply agreements with major producers, including Cameco.

On the supply side, we continue to see depressed market conditions having a negative impact on future supply potential, as suppliers struggle to justify the underlying economics. The cancellation of a planned mine expansion in Australia further supports our view that current price levels do not justify the development of new uranium supply projects. Demand growth combined with the timing, development and execution of new supply projects and the continued performance of existing supply, will determine the pace of market recovery.

Caution about forward-looking information relating to our uranium market update

This discussion of our expectations for the nuclear industry, including its growth profile, future global uranium supply and demand, and net increase in reactors, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2.

6    CAMECO CORPORATION

Industry prices

		JUN 30 2015				MAR 31 2015				DEC 31 2014				SEP 30 2014				JUN 30 2014				MAR 31 2014
Uranium ($US/lb U3O8)1
Average spot market price			36.38				39.45				35.50				35.40				28.23				34.00
Average long-term price			46.00				49.50				49.50				45.00				44.50				46.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America			7.50				7.50				8.25				7.25				7.25				7.63
Europe			8.00				8.00				8.63				7.50				7.50				8.00
Average long-term price
North America			16.00				16.00				16.00				16.00				16.00				16.00
Europe			17.00				17.00				17.00				17.00				17.00				17.00
Note: the industry does not publish UO2 prices.

¹  Average of prices reported by TradeTech and Ux Consulting (Ux)

On the spot market, where purchases call for delivery within one year, the volume reported for the second quarter of 2015 was approximately 11 million pounds. This compares to approximately 8 million pounds in the second quarter of 2014.

At the end of the quarter, the average reported spot price had declined by $3.07 (US) from the previous quarter to $36.38 (US) per pound. The average reported long-term price also declined to $46.00 (US) per pound, down $3.50 (US) from the previous quarter.

Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices escalated over the term of the contract, and market referenced prices (spot and long-term indicators quoted near the time of delivery).

Spot and long-term UF₆ conversion prices held firm during the quarter.

Shares and stock options outstanding

At July 28, 2015, we had:

• 395,792,522 common shares and one Class B share outstanding

• 8,672,964 stock options outstanding, with exercise prices ranging from $19.30 to $54.38

Dividend policy

Our board of directors has established a policy of paying a quarterly dividend of $0.10 ($0.40 per year) per common share. This policy will be reviewed from time to time based on our cash flow, earnings, financial position, strategy and other relevant factors.

2015 SECOND QUARTER REPORT    7

Financial results

This section of our MD&A discusses our performance, financial condition and outlook for the future.

Consolidated financial results

HIGHLIGHTS		THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
($ MILLIONS EXCEPT WHERE INDICATED)		2015				2014				CHANGE				2015				2014				CHANGE
Revenue			565				502				13	%			1,130				921				23	%
Gross profit			153				136				13	%			282				243				16	%
Net earnings attributable to equity holders			88				127				(31	)%			79				259				(69	)%
$ per common share (basic)			0.22				0.32				(31	)%			0.20				0.65				(69	)%
$ per common share (diluted)			0.22				0.32				(31	)%			0.20				0.65				(69	)%
Adjusted net earnings (non-IFRS, see page 9)			46				79				(42	)%			115				115				—
$ per common share (adjusted and diluted)			0.12				0.20				(40	)%			0.29				0.29				—
Cash provided by (used in) operations (after working capital changes)			(65	)			(25	)			(160	)%			68				(18	)			478	%

NET EARNINGS

Net earnings attributed to equity holders this quarter were $88 million ($0.22 per share diluted) compared to net earnings of $127 million ($0.32 per share diluted) in the second quarter of 2014. In addition to the items noted below, our net earnings were affected by mark-to-market gains on foreign exchange derivatives.

On an adjusted basis, our earnings this quarter were $46 million ($0.12 per share diluted) compared to $79 million ($0.20 per share diluted) (non-IFRS measure, see page 9) in the second quarter of 2014. The change was mainly due to:

• higher administrative costs

• a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014

partially offset by:

• higher gross profit from uranium and fuel services segments

• settlement costs of $12 million with respect to the early redemption our Series C debentures recorded during the second quarter of 2014

Net earnings in the first six months of the year were $79 million ($0.20 per share diluted) compared to $259 million ($0.65 per share diluted) in the first six months of 2014. In addition to the items noted below, our net earnings were affected by mark-to-market losses on foreign exchange derivatives. Our 2014 earnings also included a gain on the sale of our interest in BPLP of $127 million.

On an adjusted basis, our earnings for the first six months of this year were $115 million ($0.29 per share diluted) (non-IFRS measure, see page 9) unchanged from the first six months of 2014. Key variances include:

• higher administration costs

• a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014

• lower tax recovery

partially offset by:

• higher gross profit from our uranium, fuel services and NUKEM segments

• lower losses from equity accounted investments

Our 2014 adjusted net earnings were also impacted by:

• an early termination fee of $18 million incurred in 2014 as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd. (SFL), which was to expire in 2016

• settlement costs of $12 million with respect to the early redemption our Series C debentures recorded in 2014

See Financial results by segment on page 19 for more detailed discussion.

8    CAMECO CORPORATION

ADJUSTED NET EARNINGS (NON-IFRS MEASURE)

Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period, and has also been adjusted for NUKEM purchase price inventory write-downs and recoveries, income taxes on adjustments, impairment charges on non-producing property, and the after tax gain on the sale of our interest in BPLP.

Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

The following table reconciles adjusted net earnings with our net earnings.

		THREE MONTHS ENDED JUNE 30								SIX MONTHS ENDED JUNE 30
($ MILLIONS)		2015				2014				2015				2014
Net earnings attributable to equity holders			88				127				79				259
Adjustments
Adjustments on derivatives (pre-tax)			(57	)			(66	)			44				(23	)
NUKEM purchase price inventory recovery			—				—				(3	)			—
Impairment charge			—				—				6				—
Income taxes on adjustments			15				18				(11	)			6
Gain on interest in BPLP (after tax)			—				—				—				(127	)
Adjusted net earnings			46				79				115				115

2015 SECOND QUARTER REPORT    9

The following table shows what contributed to the change in adjusted net earnings this quarter.

($ MILLIONS)				THREE MONTHS ENDED JUNE 30				SIX MONTHS ENDED JUNE 30
Adjusted net earnings – 2014					79				115
Change in gross profit by segment		(We calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)
Uranium		Lower sales volume			(2	)			—
		Higher (lower) realized prices ($US)			5				(17	)
		Foreign exchange impact on realized prices			48				86
		Higher costs			(35	)			(57	)
		change – uranium			16				12
Fuel services		Higher (lower) sales volume			(5	)			1
		Higher realized prices ($Cdn)			20				20
		Higher costs			(12	)			(12	)
		change – fuel services			3				9
NUKEM		Gross profit			(2	)			9
		change – NUKEM			(2	)			9
Other changes
Higher administration expenditures					(13	)			(10	)
Higher exploration expenditures					(2	)			—
Higher income taxes					(3	)			(18	)
Contract termination fee (SFL)					—				18
Partial arbitration award					(28	)			(28	)
Debenture redemption premium					12				12
Loss on disposal of assets					6				5
Loss on equity-accounted investments					2				12
Foreign exchange losses					(18	)			(22	)
Other					(6	)			1
Adjusted net earnings – 2015					46				115

See Financial results by segment on page 19 for more detailed discussion.

Quarterly trends

HIGHLIGHTS		2015								2014																2013
($ MILLIONS EXCEPT PER SHARE AMOUNTS)		Q2				Q1				Q4				Q3				Q2				Q1				Q4				Q3
Revenue			565				566				889				587				502				419				977				597
Net earnings (loss) attributable to equity holders			88				(9	)			73				(146	)			127				131				64				211
$ per common share (basic)			0.22				(0.02	)			0.18				(0.37	)			0.32				0.33				0.16				0.53
$ per common share (diluted)			0.22				(0.02	)			0.18				(0.37	)			0.32				0.33				0.16				0.53
Adjusted net earnings (non-IFRS, see page 9)			46				69				205				93				79				36				150				208
$ per common share (adjusted and diluted)			0.12				0.18				0.52				0.23				0.20				0.09				0.38				0.53
Earnings (loss) from continuing operations			88				(10	)			72				(146	)			127				4				28				163
$ per common share (basic)			0.22				(0.02	)			0.18				(0.37	)			0.32				0.01				0.07				0.41
$ per common share (diluted)			0.22				(0.02	)			0.18				(0.37	)			0.32				0.01				0.07				0.41
Cash provided by continuing operations (after working capital changes)			(65	)			134				236				263				(25	)			7				163				154

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 75% of consolidated revenues in the second quarter of 2015

10    CAMECO CORPORATION

• the timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments, meaning quarterly results are not necessarily a good indication of annual results due to seasonal variability

• net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 9 for more information).

• cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments

The table that follows presents the differences between net earnings and adjusted net earnings for the previous seven quarters.

HIGHLIGHTS		2015								2014																2013
($ MILLIONS EXCEPT PER SHARE AMOUNTS)		Q2				Q1				Q4				Q3				Q2				Q1				Q4				Q3
Net earnings (loss) attributable to equity holders			88				(9	)			73				(146	)			127				131				64				211
Adjustments
Adjustments on derivatives (pre-tax)			(57	)			101				10				60				(66	)			44				36				(41	)
NUKEM purchase price inventory write-down (recovery)			—				(3	)			(4	)			(2	)			—				—				(3	)			17
Impairment charges			—				6				172				196				—				—				70				15
Income taxes on adjustments			15				(26	)			(46	)			(15	)			18				(12	)			(17	)			6
Gain on sale of BPLP (after tax)			—				—				—				—				—				(127	)			—				—
Adjusted net earnings (non-IFRS, see page 9)			46				69				205				93				79				36				150				208

Discontinued operation

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP, which was accounted for effective January 1, 2014. The aggregate sale price for our interest in BPLP and certain related entities was $450 million. We realized an after tax gain of $127 million on this divestiture. As a result of the transaction, we presented the results of BPLP as a discontinued operation and we revised our statement of earnings, statement of comprehensive income and statement of cash flows to reflect the change in presentation. See note 4 to the interim financial statements for more information.

Corporate expenses

ADMINISTRATION

		THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
($ MILLIONS)		2015				2014				CHANGE				2015				2014				CHANGE
Direct administration			45				35				29	%			84				74				14	%
Stock-based compensation			4				1				300	%			8				8				—
Total administration			49				36				36	%			92				82				12	%

Direct administration costs were $10 million higher for the second quarter compared to the same period last year, and $10 million higher for the first six months due to slightly higher planned expenditures related to the timing of project work and other costs, as well as costs related to our collaboration agreements.

Stock based compensation in the first six months was unchanged from 2014.

EXPLORATION

In the second quarter, uranium exploration expenses were $11 million, an increase of $2 million compared to the second quarter of 2014. Exploration expenses for the first six months of the year decreased by $1 million compared to 2014, to $23 million, due to a planned reduction in expenditures.

INCOME TAXES

We recorded an income tax recovery of $5 million in the second quarter of 2015, compared to a recovery of $6 million in the second quarter of 2014.

2015 SECOND QUARTER REPORT    11

On an adjusted basis, we recorded an income tax recovery of $20 million this quarter compared to recovery of $23 million in the second quarter of 2014. In 2015, we recorded losses of $164 million in Canada compared to $116 million in 2014, while earnings in foreign jurisdictions increased to $190 million from $171 million. The resulting increase in income tax recovery in Canada is more than offset by increased tax expense in the foreign jurisdictions.

In the first six months of 2015, we recorded an income tax recovery of $50 million compared to a recovery of $51 million in 2014.

On an adjusted basis, we recorded an income tax recovery of $39 million for the first six months compared to a recovery of $57 million in 2014 due to higher pre-tax adjusted earnings and increased tax expense in foreign jurisdictions in 2015.

		THREE MONTHS ENDED JUNE 30								SIX MONTHS ENDED JUNE 30
($ MILLIONS)		2015				2014				2015				2014
Pre-tax adjusted earnings1
Canada2			(164	)			(116	)			(267	)			(266	)
Foreign			190				171				342				323
Total pre-tax adjusted earnings			26				55				75				57
Adjusted income taxes1
Canada2			(33	)			(29	)			(59	)			(66	)
Foreign			13				6				20				9
Adjusted income tax expense (recovery)			(20	)			(23	)			(39	)			(57	)

¹  Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures.

²  Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 9).

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with Canada Revenue Agency (CRA) since 2008, when it originated, and with the United States Internal Revenue Service (IRS) since the first quarter of 2015. Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing disputes we have.

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of cases like ours. However, tax authorities generally test two things:

• the governance (structure) of the corporate entities involved in the transactions

• the price at which goods and services are sold by one member of a corporate group to another

We have a global customer base and we established a marketing and trading structure involving foreign subsidiaries, including Cameco Europe Limited (CEL), which entered into various intercompany arrangements, including purchase and sale agreements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts between arm’s-length parties entered into at that time.

For the years 2003 to 2009, CRA has shifted CEL’s income (as re-calculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. The IRS also allocated a portion of CEL’s income for 2009 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $290 million for the 2003 – 2014 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options including remedies under international tax treaties that would limit double taxation; however, there is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.

CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2009 tax returns. We have recorded a cumulative tax provision of $89 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through June 30, 2015. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

12    CAMECO CORPORATION

For the years 2003 through 2009, CRA issued notices of reassessment for approximately $2.8 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $820 million. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that require larger companies like us to remit 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have paid a net amount of $230 million cash to the Government of Canada, which includes the amounts shown in the table below. As an alternative to paying cash, we are exploring the possibility of providing security in the form of letters of credit to satisfy our requirements under these provisions.

YEAR PAID ($ MILLIONS)		CASH TAXES				INTEREST AND INSTALMENT PENALTIES				TRANSFER PRICING PENALTIES				TOTAL
Prior to 2013			—				13				—				13
2013			1				9				36				46
2014			106				47				—				153
2015			(62	)			1				79				18
Total			45				70				115				230

Using the methodology we believe CRA will continue to apply, and including the $2.8 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $6.6 billion of additional income taxable in Canada for the years 2003 through 2014, which would result in a related tax expense of approximately $1.9 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.45 billion and $1.5 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to us. While in dispute, we would be responsible for remitting or otherwise providing security for 50% of the cash taxes and transfer pricing penalties (between $725 million and $750 million), plus related interest and instalment penalties assessed, which would be material to us.

Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. The estimated amounts summarized in the table below reflect actual amounts paid and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2014. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2014.

$ MILLIONS		2003 - 2014				2015				2016 - 2017				2018 - 2023				TOTAL
50% of cash taxes and transfer pricing penalties paid or owing in the period1			143				165 - 190				320 - 345				80 - 105				725 - 750

¹  These amounts do not include interest and instalment penalties, which totalled approximately $70 million to June 30, 2015.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $230 million already paid to date.

Due to the time it is taking to work through the pre-trial process, we now expect our appeal of the 2003 reassessment to be heard in the Tax Court of Canada in 2016. If this timing is adhered to, we expect to have a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

In the first quarter, we received a Revenue Agent’s Report (RAR) from the IRS challenging the transfer pricing used under certain intercompany transactions pertaining to the 2009 tax year for certain of our US subsidiaries. The RAR lists the adjustments proposed by the IRS and calculates the tax and any penalties owing based on the proposed adjustments.

The current position of the IRS is that a portion of the non-US income reported under our corporate structure and taxed in non-US jurisdictions should be recognized and taxed in the US on the basis that:

• the prices received by our US mining subsidiaries for the sale of uranium to CEL are too low

• the compensation being earned by Cameco Inc., one of our US subsidiaries, is inadequate

2015 SECOND QUARTER REPORT    13

The proposed adjustments result in an increase in taxable income in the US of approximately $108 million (US) and a corresponding increased income tax expense of approximately $32 million (US) for the 2009 taxation year, with interest being charged thereon. In addition, the IRS proposed penalties of approximately $7 million (US) in respect of the adjustment.

At present, the RAR pertains only to the 2009 tax year: however, the IRS is also auditing our tax returns for 2010 through 2012 on a similar basis and we expect adjustments in these years to be similar to those made for 2009. If the IRS audits years subsequent to 2012 on a similar basis, we expect these proposed adjustments would also be similar to those made for 2009.

We believe that the conclusions of the IRS in the RAR are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. At present, this matter is still at an early stage and, until this matter progresses further, we cannot provide an estimation of the likely timeline for a resolution of the dispute.

We believe that the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

Caution about forward-looking information relating to our CRA and IRS tax disputes

This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

Assumptions

• CRA will reassess us for the years 2010 through 2014 using a similar methodology as for the years 2003 through 2009, and the reassessments will be issued on the basis we expect

• we will be able to apply elective deductions and tax loss carryovers to the extent anticipated

• CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years 2007 through 2009) in addition to interest charges and instalment penalties

• we will be substantially successful in our dispute with CRA and the cumulative tax provision of $89 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

• IRS will continue to propose adjustments for the years 2010 through 2012 and may propose adjustments for later years

• we will be substantially successful in our dispute with IRS

Material risks that could cause actual results to differ materially

• CRA reassesses us for years 2010 through 2014 using a different methodology than for years 2003 through 2009, or we are unable to utilize elective deductions and tax loss carryovers to the same extent as anticipated, resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected

• the time lag for the reassessments for each year is different than we currently expect

• we are unsuccessful and the outcomes of our dispute with CRA and/or IRS result in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows

• cash tax payable increases due to unanticipated adjustments by CRA or IRS not related to transfer pricing

• IRS proposes adjustments for years 2010 through 2014 using a different methodology than for 2009

• we are unable to effectively eliminate all double taxation

FOREIGN EXCHANGE

At June 30, 2015:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.25 (Cdn), down from $1.00 (US) for $1.27 (Cdn) at March 31, 2015. The exchange rate averaged $1.00 (US) for $1.23 (Cdn) over the quarter.

• We had foreign currency forward contracts of $1.3 billion (US), €15 million (EUR), and foreign currency options of $130 million (US). The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.16 (Cdn), US currency option contracts had an average exchange rate range of $1.00 (US) for $1.22 to $1.28 (Cdn), and €1.00 for $1.12 (US) for EUR currency contracts.

• The mark-to-market loss on all foreign exchange contracts was $120 million at June 30, 2015 compared to a $184 million loss at March 31, 2015.

14    CAMECO CORPORATION

Outlook for 2015

Our strategy is to profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.

Our outlook for 2015 reflects the expenditures necessary to help us achieve our strategy. Our outlook for NUKEM revenue and unit cost, as well as consolidated revenue, administration costs and tax rate has changed. To provide additional insight following our acquisition of NUKEM in 2013, we provided an outlook for NUKEM’s direct administration costs and tax rate. However, NUKEM’s direct administration costs and tax rate are immaterial in the context of our consolidated results. We provide outlook for consolidated direct administration costs and for our consolidated tax rate based on taxes incurred in Canada and in foreign jurisdictions; we do not provide any further breakdown for our other segments. As a result, we will no longer provide an outlook for direct administration costs or tax rate specific to the NUKEM segment. We do not provide an outlook for the items in the table that are marked with a dash.

See 2015 Financial results by segment on page 19 for details.

2015 FINANCIAL OUTLOOK

		CONSOLIDATED		URANIUM		FUEL SERVICES		NUKEM
Production		—		25.3 to 26.3 million lbs		9 to 10 million kgU		—
Sales volume1		—		31 to 33 million lbs		Decrease 5% to 10%		7 to 8 million lbs  U3O8
Revenue compared to 20142		Increase 5% to 10%		Increase up to 5%3		Increase up to 5%		Increase 20% to 25%
Average unit cost of sales (including D&A)		—		Increase 5% to 10%4		Increase 5% to 10%		Increase 5% to 10%
Direct administration costs compared to 20145		Increase 5% to 10%		—		—		—
Exploration costs compared to 2014		—		Decrease 5% to 10%		—		—
Tax rate		Recovery of 40% to 45%		—		—		—
Capital expenditures		$405 million		—		—		—

¹ Our 2015 outlook for sales volume does not include sales between our uranium, fuel services and NUKEM segments.

²  For comparison of our 2015 outlook and 2014 results for revenue, we do not include sales between our uranium, fuel services and NUKEM segments.

³  Based on a uranium spot price of $36.00 (US) per pound (the Ux spot price as of July 27, 2015), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on July 27, 2015) and an exchange rate of $1.00 (US) for $1.22 (Cdn).

⁴  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2015, then we expect the overall unit cost of sales to increase further.

⁵  Direct administration costs do not include stock-based compensation expenses. See page 11 for more information.

Our outlook for NUKEM revenue has changed to an increase of 20% to 25% (previously increase of 5% to 10%) due to our expectation that NUKEM sales volumes will be higher in the range, and the effect of foreign exchange. Consolidated revenue is now expected to increase by 5% to 10% (previously an increase of up to 5%) due to our expectation that sales volumes for the uranium and NUKEM segments will be higher in the range.

We have also adjusted our outlook for NUKEM cost of sales. Unit cost of sales is now expected to increase 5% to 10% (previously increase up to 5%) due to the effect of foreign exchange.

Consolidated administration costs are now expected to increase 5% to 10% (previously an increase of up to 5%) due to increased costs under our collaboration agreements and the effect of foreign exchange.

We have adjusted our outlook for the consolidated tax rate to a recovery of 40% to 45% (previously 45% to 50%) due to the expected impact of the changes to the consolidated outlook noted above, and a change in the distribution of earnings between jurisdictions.

2015 SECOND QUARTER REPORT    15

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales volumes and revenue can vary significantly however, the majority of delivery notices have been received for 2015, reducing variability for the remainder of the year. We expect uranium deliveries in the third quarter to be similar to the first two quarters, and fourth quarter deliveries to be higher.

REVENUE AND EARNINGS SENSITIVITY ANALYSIS

For the rest of 2015:

• an increase of $5 (US) per pound in both the Ux spot price ($36.00 (US) per pound on July 27, 2015) and the Ux long-term price indicator ($44.00 (US) per pound on July 27, 2015) would increase revenue by $48 million and net earnings by $27 million. Conversely, a decrease of $5 (US) per pound would decrease revenue by $45 million and net earnings by $24 million.

• a one-cent change in the value of the Canadian dollar versus the US dollar would change adjusted net earnings by $5 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following table and graph are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on June 30, 2015 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on June 30, 2015 and none of the assumptions we list below change.

We intend to update this table and graph each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio. As a result, we expect the table and graph to change from quarter to quarter.

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

SPOT PRICES ($US/lb U3O8)		$20				$40				$60				$80				$100				$120				$140
2015			44				45				50				54				59				64				68
2016			40				46				57				68				78				88				96
2017			39				46				56				67				78				88				95
2018			40				47				58				69				79				88				96
2019			41				48				59				69				78				86				92

The table and graph illustrate the mix of long-term contracts in our June 30, 2015 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to June 30, 2015.

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices.

16    CAMECO CORPORATION

Our portfolio is affected by more than just the spot price. We made the following assumptions (which are not forecasts) to create the table:

Sales

• sales volumes on average of 29 million pounds per year, with commitment levels in 2015 through 2018 higher than in 2019

• excludes sales between our uranium, fuel services and NUKEM segments

Deliveries

• deliveries include best estimates of requirements contracts and contracts with volume flex provisions

• we defer a portion of deliveries under existing contracts for 2015

Annual inflation

• is 2% in the US

Prices

• the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 19% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table and graph will be higher

Liquidity and capital resources

Our financial objective is to make sure we have the cash and debt capacity to fund our operating activities, investments and growth.

We have large, creditworthy customers that continue to need uranium even during weak economic conditions, and we expect the uranium contract portfolio we have built to provide a solid revenue stream for years to come.

We expect to continue investing in maintaining and prudently expanding our production capacity over the next several years. We have a number of alternatives to fund future capital requirements, including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. However, we expect our cash balances and operating cash flows will meet our anticipated 2015 capital requirements without the need for significant additional funding.

We have an ongoing dispute with CRA regarding our offshore marketing company structure and related transfer pricing arrangements. See page 12 for more information. Until this dispute is settled, we expect to make cash payments to CRA for 50% of the cash taxes payable and the related interest and instalment penalties. We have provided an estimate of the amount and timing of the expected cash taxes payable in the table on page 13. As an alternative to paying cash, we are exploring the possibility of providing security in the form of letters of credit to satisfy our requirements under the tax provisions.

CASH FROM OPERATIONS

Cash from continuing operations was $40 million lower this quarter than in the second quarter of 2014. Contributing to this change was an increase in working capital requirements and a decrease in income taxes paid. Working capital required $78 million more in 2015, largely as a result of an increase in inventory, partially offset by changes in other working capital items during the quarter. Not including working capital requirements, our operating cash flows this quarter were higher by $38 million.

Cash from continuing operations was $86 million higher in the first six months of 2015 than for the same period in 2014 due largely to a decrease in income taxes paid. Working capital required $8 million more in 2015. Not including working capital requirements, our operating cash flows in the first six months were higher by $94 million.

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.4 billion at June 30, 2015, down $0.1 billion from March 31, 2015. At June 30, 2015, we had approximately $1.0 billion outstanding in letters of credit.

Debt covenants

We are bound by certain covenants in our unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at June 30, 2015, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2015 to be constrained by them.

2015 SECOND QUARTER REPORT    17

Long-term contractual obligations

Since December 31, 2014, there have been no material changes to our long-term contractual obligations. Please see our annual MD&A for more information.

OFF-BALANCE SHEET ARRANGEMENTS

We had two kinds of off-balance sheet arrangements at June 30, 2015:

• purchase commitments

• financial assurances

Purchase commitments

The following table is based on our purchase commitments at June 30, 2015. These commitments include a mix of fixed price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of purchase. We will update this table as required in our MD&A to reflect changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

JUNE 30 ($ MILLIONS)		2015				2016 AND 2017				2018 AND 2019				2020 AND BEYOND				TOTAL
Purchase commitments1			461				941				379				541				2,322

¹  Denominated in US dollars, converted to Canadian dollars as of June 30, 2015 at the rate of $1.25.

During the second quarter, our purchase commitments increased due to the signing of new long-term purchase commitments, which we believe will be beneficial for us as they have been in the past.

As of June 30, 2015, we had commitments of about $2.3 billion for the following:

• approximately 33 million pounds of U₃O₈ equivalent from 2015 to 2028

• approximately 5 million kgU as UF₆ in conversion services from 2015 to 2018

• about 0.7 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions.

Financial assurances

At June 30, 2015 our financial assurances totaled $1.0 billion compared to $1.1 billion at March 31, 2015. The decrease is mainly due to a reduction to reclamation letters of credit in Wyoming, as well as exchange rate fluctuations.

BALANCE SHEET

($ MILLIONS)		JUN 30, 2015				DEC 31, 2014				CHANGE
Cash, short-term investments and bank overdraft			331				567				(42	)%
Total debt			1,492				1,491				—
Inventory			1,255				902				39	%

Total cash and short-term investments at June 30, 2015 were $331 million, or 42% lower than at December 31, 2014, primarily due to capital expenditures of $195 million, dividend payments of $79 million, and interest payments of $35 million, partially offset by cash provided by operations of $68 million. Net debt at June 30, 2015 was $1,161 million.

Total debt remained largely unchanged from December 31, 2014. See notes 15 and 16 of our audited annual financial statements for more detail.

Total product inventories increased to $1,255 million, including NUKEM’s inventories ($313 million). Uranium inventories increased as sales were lower than production and purchases in the first six months of the year.

Fuel services inventories increased as sales were also lower than production and purchases.

18    CAMECO CORPORATION

Financial results by segment

Uranium

						THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
HIGHLIGHTS						2015				2014				CHANGE				2015				2014				CHANGE
Production volume (million lbs)							5.4				4.0				35	%			10.5				9.7				8	%
Sales volume (million lbs)1							7.3				7.4				(1	)%			14.3				14.3				—
Average spot price		($	US/lb)				36.17				28.97				25	%			37.26				31.95				17	%
Average long-term price		($	US/lb)				47.50				44.83				6	%			48.50				46.75				4	%
Average realized price		($	US/lb)				46.57				45.93				1	%			45.03				46.26				(3	)%
		($	Cdn/lb)				58.04				50.76				14	%			55.45				50.67				9	%
Average unit cost of sales (including D&A)		($	Cdn/lb)				40.71				35.86				14	%			38.64				34.63				12	%
Revenue ($ millions)1							424				376				13	%			791				724				9	%
Gross profit ($ millions)							127				110				15	%			240				229				5	%
Gross profit (%)							30				29				3	%			30				32				(6	)%

¹  Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil pounds in sales and nil revenue in Q2, 2015; 165,000 pounds and revenue of $5.0 million in Q2, 2014; 15,000 pounds in sales and revenue of $0.5 million in the first six months of 2015; 165,000 pounds and revenue of $5.0 million in the first six months of 2014).

SECOND QUARTER

Production volumes this quarter were 35% higher compared to the second quarter of 2014, mainly due to production from Cigar Lake and higher production from McArthur River/Key Lake, which was partially offset by lower production at Rabbit Lake, Inkai and our US operations. See Uranium 2015 Q2 updates starting on page 22 for more information.

The 13% increase in uranium revenues was a result of a 14% increase in the Canadian dollar average realized price, partially offset by a 1% decrease in sales volume.

The US dollar average realized price increased by 1% compared to 2014 mainly due to higher prices on fixed price contracts, while the higher Canadian dollar realized prices this quarter were a result of the weakening of the Canadian dollar compared to 2014. This quarter the exchange rate on the average realized price was $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) in the second quarter of 2014.

Total cost of sales (including D&A) increased by 12% ($297 million compared to $266 million in 2014) due to a 14% increase in the unit cost of sales, partially offset by a 1% decrease in sales volume. The increase in the unit cost of sales was mainly the result of an increase in the volume of material purchased in the quarter at prices higher than our average cost of inventory.

The net effect was a $17 million increase in gross profit for the quarter.

FIRST SIX MONTHS

Production volumes for the first six months of the year were 8% higher than in the previous year due to the addition of production from Cigar Lake, partially offset by lower production at McArthur/Key Lake, our US operations and Inkai. See Uranium 2015 Q2 updates starting on page 22 for more information.

Uranium revenues increased 9% compared to the first six months of 2014 due to a 9% increase in the Canadian dollar average realized price. Sales volumes in the first six months were the same as in 2014.

Our Canadian dollar realized prices for the first six months of 2015 were higher than 2014, primarily as a result of the weakening of the Canadian dollar compared to 2014. For the first six months of 2015, the exchange rate on the average realized price was $1.00 (US) for $1.23 (Cdn) compared to $1.00 (US) for $1.10 (Cdn) for the same period in 2014.

Total cost of sales (including D&A) increased by 12% ($552 million compared to $495 million in 2014) mainly due to a 12% increase in the unit cost of sales. The increase was mainly the result of an increase in the volume of material purchased in the first six months at prices higher than our average cost of inventory, and an increase in unit production costs.

The net effect was an $11 million increase in gross profit for the first six months.

We are active in the uranium market, buying and selling uranium on the spot market and under long-term contracts when we expect it will be beneficial for us. Purchases are impacted by foreign exchange rates, and may, in some cases, require we pay prices higher or lower than current spot prices. Depending on the volume and unit cost of purchases in a quarter, our average cost of inventory can be impacted, which flows through to our cost of sales.

2015 SECOND QUARTER REPORT    19

The table below shows the costs of produced and purchased uranium incurred in the reporting periods (which are non-IFRS measures, see the paragraphs below the table). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

		THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
($CDN/LB)		2015				2014				CHANGE				2015				2014				CHANGE
Produced
Cash cost			26.53				26.24				1	%			27.28				23.03				18	%
Non-cash cost			14.64				14.72				(1	)%			13.59				12.25				11	%
Total production cost			41.17				40.96				1	%			40.87				35.28				16	%
Quantity produced (million lbs)			5.4				4.0				35	%			10.5				9.7				8	%
Purchased
Cash cost			45.68				58.15				(21	)%			46.69				44.76				4	%
Quantity purchased (million lbs)			4.0				0.3				1233	%			6.6				1.6				313	%
Totals
Produced and purchased costs			43.09				42.16				2	%			43.12				36.62				18	%
Quantities produced and purchased (million lbs)			9.4				4.3				119	%			17.1				11.3				51	%

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.

These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the second quarter and the first six months of 2015 and 2014.

Cash and total cost per pound reconciliation

		THREE MONTHS ENDED JUNE 30								SIX MONTHS ENDED JUNE 30
($ MILLIONS)		2015				2014				2015				2014
Cost of product sold			251.2				204.6				455.4				385.6
Add / (subtract)
Royalties			(21.9	)			(21.0	)			(35.7	)			(35.2	)
Standby charges			—				(9.7	)			—				(19.0	)
Other selling costs			(3.7	)			(3.2	)			(5.3	)			(5.5	)
Change in inventories			100.4				(48.3	)			180.2				(30.9	)
Cash operating costs (a)			326.0				122.4				594.6				295.0
Add / (subtract)
Depreciation and amortization			45.9				60.9				96.1				109.2
Change in inventories			33.2				(2.0	)			46.7				9.6
Total operating costs (b)			405.1				181.3				737.4				413.8
Uranium produced & purchased (million lbs) (c)			9.4				4.3				17.1				11.3
Cash costs per pound (a ÷ c)			34.68				28.47				34.77				26.11
Total costs per pound (b ÷ c)			43.09				42.16				43.12				36.62

20    CAMECO CORPORATION

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

						THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
HIGHLIGHTS						2015				2014				CHANGE				2015				2014				CHANGE
Production volume (million kgU)							3.1				3.8				(18	)%			5.7				7.8				(27	)%
Sales volume (million kgU)							2.4				3.3				(27	)%			5.4				5.1				6	%
Average realized price		($	Cdn/kgU	)			29.70				21.28				40	%			25.45				21.68				17	%
Average unit cost of sales (including D&A)		($	Cdn/kgU	)			21.44				16.46				30	%			20.39				18.19				12	%
Revenue ($ millions)							70				70				—				136				110				24	%
Gross profit ($ millions)							19				16				19	%			27				18				50	%
Gross profit (%)							27				23				17	%			20				16				25	%

SECOND QUARTER

Total revenue for the second quarter of 2015 remained the same as the prior year at $70 million. A 27% decrease in sales volumes was offset by a 40% increase in average realized price, primarily due to the mix of products sold.

The total cost of products and services sold (including D&A) decreased by 7% ($50 million compared to $54 million in the second quarter of 2014) due to the decrease in sales volumes, partially offset by an increase in the average unit cost of sales. When compared to 2014, the average unit cost of sales was 30% higher due to the mix of fuel services products sold.

The net effect was a $3 million increase in gross profit.

FIRST SIX MONTHS

In the first six months of the year, total revenue increased by 24% due to a 6% increase in sales volumes and a 17% increase in realized price that was the result of increased realized prices for UF₆ and the mix of products sold.

The total cost of sales (including D&A) increased 17% ($109 million compared to $93 million in 2014) due to an increase in sales volume and a 12% increase in the average unit cost of sales, which resulted from the mix of fuel services products sold.

The net effect was a $9 million increase in gross profit.

NUKEM

						THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
HIGHLIGHTS						2015				2014				CHANGE				2015				2014				CHANGE
Uranium sales (million lbs)1							1.5				1.5				—				4.0				2.2				82	%
Average realized price			($Cdn/lb)				50.47				41.63				21	%			42.80				41.01				4	%
Cost of product sold (including D&A)							70				49				43	%			156				84				86	%
Revenue ($ millions)1							81				62				31	%			178				94				89	%
Gross profit ($ millions)							11				13				(15	)%			22				10				120	%
Gross profit (%)							14				21				(33	)%			12				11				9	%

¹  Includes sales and revenue between our uranium, fuel services and NUKEM segments (200,000 pounds in sales and revenue of $10.8 million in Q2, 2015, nil in Q2, 2014; 743,0000 pounds in sales and revenue of $13.3 million in the first six of 2015, nil in the first six of 2014).

SECOND QUARTER

During the second quarter of 2015, NUKEM delivered 1.5 million pounds of uranium, unchanged from the same period last year. Total revenues increased by 31% as a result of average realized prices which were 21% higher than those realized in the second quarter of 2014.

Gross margin percentage was 14% in the second quarter of 2015, a 33% decrease compared to the second quarter of 2014. The allocation of the historic purchase price to the sale of inventory on hand at the time of acquisition of NUKEM, impacted margins for the quarter.

The net effect was a $2 million decrease in gross profit.

2015 SECOND QUARTER REPORT    21

FIRST SIX MONTHS

During the six months ended June 30, 2015, NUKEM delivered 4.0 million pounds of uranium, an increase of 82%, due to timing of customer requirements and generally lower activity in the market during 2014. Total revenues increased 89% due to an 82% increase in sales volumes and a 4% increase in average realized price.

Gross margin percentage was 12% for the first six months of 2015 as compared to 11% for the same period in 2014. Included in the 2014 margin was a $6 million write-down of inventory compared to a $3 million recovery in 2015. The write-down in 2014 was a result of a decline in the spot price during the period.

The net effect was a $12 million increase in gross profit.

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 35% higher than the second quarter of 2014, and 8% higher for the first six months. See below for more information.

URANIUM PRODUCTION

		THREE MONTHS ENDED JUNE 30												SIX MONTHS ENDED JUNE 30
OUR SHARE (MILLION LBS)		2015				2014				CHANGE				2015				2014				CHANGE				2015 PLAN
McArthur River/Key Lake			2.9				2.1				38	%			5.5				5.9				(7	)%			13.7
Cigar Lake1			1.2				—				—				1.6				—				—				3.0 – 4.0
Inkai			0.6				0.7				(14	)%			1.2				1.4				(14	)%			3.0
Rabbit Lake			0.2				0.6				(67	)%			1.1				1.1				—				3.9
Smith Ranch-Highland			0.4				0.5				(20	)%			0.9				1.0				(10	)%			1.4
Crow Butte			0.1				0.1				—				0.2				0.3				(33	)%			0.3
Total			5.4				4.0				35	%			10.5				9.7				8	%			25.3 – 26.3

¹  Commercial production achieved on May 1, 2015 – see Cigar Lake update below.

Uranium 2015 Q2 updates

UPDATE TO FOREST FIRE SITUATION IN NORTHERN SASKATCHEWAN

The forest fire situation in northern Saskatchewan has been improving over the last few weeks and all evacuees have now been allowed to return home. Air and road access to our operations has improved and we have resumed normal shipping of packaged product from our operations. We still expect to meet our 2015 production target of 25.3 million to 26.3 million pounds, and our sales target of 31 million to 33 million pounds.

The fire risk across northern Saskatchewan has diminished, although we continue to monitor the situation closely and support our employees, their families and communities impacted by the situation.

MCARTHUR RIVER/KEY LAKE

Production update

Production for the quarter was 38% higher compared to the same period last year but 7% lower for the first half of the year due to the timing of mill maintenance, including an unplanned mill maintenance outage during the first quarter. The operation remains on track to achieve our planned 2015 production.

Licensing and production capacity update

We now have a licence production limit of 25 million pounds per year (100% basis) at both McArthur River and Key Lake. The increased production limit aligns with our strategy to maintain the flexibility to adjust to market conditions.

22    CAMECO CORPORATION

CIGAR LAKE

Production update

The jet boring system at the Cigar Lake mine continued to perform as expected, and during the first half of 2015, we successfully mined 4.8 million pounds of uranium for shipment to the McClean Lake mill. We are continuing to ramp up mine production, and now have three jet boring machines (JBS) commissioned for use underground.

The mined ore is routinely transported to the McClean Lake mill, which, during the second quarter, packaged approximately 2.4 million pounds (100% basis, 1.2 million pounds our share), for total production of 3.1 million pounds during the first half of 2015. Cigar Lake remains on track to achieve the annual production target of 6 million to 8 million packaged pounds (100% basis).

Commercial production

Commercial production signals a transition in the accounting treatment for costs incurred at the mine. Cigar Lake met all of the criteria for commercial production, including cycle time and process specifications, in the second quarter. Therefore, effective May 1, 2015, we began charging all production costs, including depreciation, to inventory and subsequently recognizing them in cost of sales as the product is sold.

Rampup schedule

We expect Cigar Lake to produce between 6 million and 8 million packaged pounds in 2015; our share is 3 million to 4 million pounds. As we ramp up production to 18 million pounds (100% basis) by 2018, volumes may not be linear year-to-year, but will vary based on our operational experience. To ensure the most efficient operation of the mine and mill throughout the year, we expect to continually manage ore supply and, therefore, may halt and resume mining several times during a quarter without impacting planned annual production.

Caution about forward-looking information relating to Cigar Lake

This discussion of our expectations for Cigar Lake, including our plan for 6 million to 8 million packaged pounds (100%) in 2015, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2.

INKAI

Production update

Production was 14% lower for both the second quarter and the first six months of the year compared to the same periods in 2014 due to the timing of new wellfield development. The operation remains on track to achieve our planned 2015 production.

Block 3

The block 3 test leach facility is now operational and state commissioning of the test wellfields was accomplished during the second quarter. Our application for an extension of the block 3 deposit evaluation period is still pending final approval from the Ministry of Energy of the Republic of Kazakhstan. Inkai continues working on the final appraisal of the mineral potential of block 3 according to Kazakhstan standards.

RABBIT LAKE

Production update

Production for the quarter was 67% lower than the same period last year due to the timing of our planned mill maintenance outage. Production for the first six months was unchanged from 2014 and the operation remains on track to achieve our planned 2015 production.

Tailings capacity

Our plan for fully utilizing the currently available tailings capacity at Rabbit Lake requires regulatory approval in 2016 and the process to obtain that approval has begun. We expect to have sufficient tailings capacity to support milling of Eagle Point ore until about 2018 (based upon expected ore tonnage, milling rate and tailings performance), subject to obtaining regulatory approval.

2015 SECOND QUARTER REPORT    23

SMITH RANCH-HIGHLAND AND CROW BUTTE

Production update

At our US operations, as expected, total production was 17% lower for the quarter and 15% lower for the first six months compared to the same periods in 2014 primarily due to a declining head grade at Crow Butte, where there are no new wellfields being developed under the current mine plan.

Fuel services 2015 Q2 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 3.1 million kgU in the second quarter, 18% lower than the same period last year. Production for the first six months was 27% lower than last year, primarily due to the reduced volumes attributable to the early termination of the SFL contract in 2014. We decreased our production target in 2015 to between 9 million and 10 million kgU, so quarterly production is expected to be lower than comparable periods in 2014.

Labour relations

Approximately 100 unionized employees at Cameco Fuel Manufacturing Inc.‘s operations in Port Hope and Cobourg, Ontario accepted a new collective agreement.

The employees, represented by the United Steelworkers local 14193, agreed to a three-year contract that includes a 7% wage increase over the term of the agreement. The previous contract expired on June 1, 2015.

Qualified persons

The technical and scientific information discussed in this document for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:

MCARTHUR RIVER/KEY LAKE

• David Bronkhorst, vice-president, mining and technology, Cameco

CIGAR LAKE

• Les Yesnik, general manager, Cigar Lake, Cameco

INKAI

• Darryl Clark, general director, JV Inkai

24    CAMECO CORPORATION

Additional information

Critical accounting estimates

Due to the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.

Controls and procedures

As of June 30, 2015, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of June 30, 2015, the CEO and CFO concluded that:

• the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required

• such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

2015 SECOND QUARTER REPORT    25