EX-99.2 3 d276143dex992.htm EX-99.2

EX-99.2

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Exhibit 99.2

Management’s discussion and analysis

for the quarter ended September 30, 2016

THIRD QUARTER UPDATE			4
CONSOLIDATED FINANCIAL RESULTS			6
OUTLOOK FOR 2016			13
LIQUIDITY AND CAPITAL RESOURCES			15
FINANCIAL RESULTS BY SEGMENT
URANIUM			17
FUEL SERVICES			19
NUKEM			20
OUR OPERATIONS
URANIUM 2016 Q3 UPDATES			21
FUEL SERVICES 2016 Q3 UPDATES			21
QUALIFIED PERSONS			21
ADDITIONAL INFORMATION			22

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 September 30, 2016 (interim financial statements). The information is based on what we knew as of November 1, 2016 and updates our first quarter, second quarter and annual MD&A included in our 2015 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, 2015 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.

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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, second quarter 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 2016 and future global uranium supply and demand, including the discussion under the heading Uranium market update

• the discussion of our expectations relating to our Canada Revenue Agency (CRA) and Internal Revenue Service (IRS) 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 2016

• our expectations for uranium deliveries for the fourth quarter of 2016

• our price sensitivity analysis for our uranium segment

• our expectation that our cash balances and operating cash flows will meet our anticipated 2016 capital requirements

• our expectation that our operating and investment activities for the remainder of 2016 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

• our expectations related to annual Rabbit Lake care and maintenance costs

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 currency exchange rates, interest rates, royalty 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, care and maintenance, 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

• we are unable to utilize letters of credit to the extent anticipated in our dispute with CRA

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

• our mineral reserve and resource estimates are not reliable, or we face challenging or unexpected 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 expectations relating to Rabbit Lake care and maintenance costs prove to be inaccurate

• 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 for any reason

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• any difficulties with the McClean Lake mill modifications or expansion or milling of Cigar Lake ore

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

• our operations are disrupted due to problems with our own or our suppliers’ or 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, royalty rates, currency exchange rates and interest rates

• our expectations about the outcome of disputes with tax authorities

• we are able to utilize letters of credit to the extent anticipated in our dispute with CRA

• our decommissioning and reclamation expenses

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

• our understanding of 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

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

• that annual Rabbit Lake care and maintenance costs will be as expected

• 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

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Third quarter update

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 from our tier-one assets at a pace aligned with market signals to increase long-term shareholder value, and to do that with an emphasis on safety, people and the environment.

We believe the best way to create value is to focus our investible capital on maintaining a strong balance sheet and on preserving the production flexibility of our tier-one assets. This approach provides us with the opportunity to meet rising demand with increased production from our best margin assets, and helps to mitigate risk during a prolonged period of uncertainty. In the context of continued depressed market conditions, we have positioned our production to come from our lower-cost operations.

Going forward, we plan to:

• ensure continued safe, reliable, low-cost production from our tier-one assets – McArthur River/Key Lake, Cigar Lake and Inkai

• complete ramp up of production at Cigar Lake

• continue to evaluate the position of the other sources of supply in our portfolio, including Rabbit Lake and the US operations, and retain the flexibility to respond to market signals and take advantage of value adding opportunities, including expanded production capacity at McArthur River/Key Lake and at Inkai

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

You can read more about our strategy in our 2015 annual management’s discussion and analysis (MD&A).

Strategy in action

Since the accident at Fukushima over five years ago, our industry has faced considerable market challenges, with the uranium spot price down 70% and term price down 45%. While we cannot control the conditions in the market, we have not been complacent. We have taken action – focussing on our tier-one assets, streamlining the company, demonstrating supply discipline, protecting and even extending the value of our contract portfolio, and maintaining our focus on safety, people and the environment.

And, we have seen results from our actions. We have continued to achieve average realized prices above market prices, and taken steps to reduce our operating expenses, capital expenditures, and general and administrative spend, and maintained our investment grade rating. Ultimately, we have stayed competitive, protected our balance sheet, and positioned the company for price and operating leverage.

Going forward, we will continue to look for opportunities to enhance the value of the company for our shareholders, including further strengthening our balance sheet.

Uranium market update

The market remained weak during the third quarter, with low demand and persistent oversupply driving both spot and term prices down to new 10-year lows.

New reactor startups continued to be a bright spot, with four more reactors – two in China, one in India, one in Russia – added to the grid, bringing the 2016 total to nine. However, the generally anemic sentiment in the nuclear space was unchanged amid continued uncertainty around the path for restarting reactors in Japan, and economic pressure on nuclear operators in the United States. Despite the prolonged stress on near-term demand, there have been very few adjustments to primary supply, softening market conditions to where they are today.

We expect the market environment to remain depressed until catalysts such as reactor restarts in Japan take place, primary suppliers react to low uranium price, excess supply clears the market, and there is a significant return to long-term contracting.

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Longer-term, uranium demand is backed by steady reactor growth that supports a positive story for the industry. Over the next decade, as the 57 reactors under construction today come online, and as planned units move into the construction phase, the increasing demand will have to be met with new primary supply. However, today’s low uranium prices and lack of long-term contracting are delaying the development of those new supply sources, adding uncertainty to security of supply, and favouring established producers that will be able to draw upon low-cost, long-lived assets for stable future production.

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 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.

Industry prices at quarter end

		SEP 30 2016				JUN 30 2016				MAR 31 2016				DEC 31 2015				SEP 30 2015				JUN 30 2015
Uranium ($US/lb U3O8)1
Average spot market price			23.00				26.70				28.70				34.23				36.38				36.38
Average long-term price			37.50				40.50				43.50				44.00				44.00				46.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America			5.93				6.75				6.75				6.88				7.00				7.50
Europe			6.45				7.25				7.25				7.38				7.50				8.00
Average long-term price
North America			12.25				12.75				12.75				13.50				15.00				16.00
Europe			13.00				14.00				14.00				14.50				16.25				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 by Ux Consulting (UxC) for the third quarter of 2016 was approximately 12 million pounds. This compares to approximately 10 million pounds in the third quarter of 2015. At the end of the quarter, the average reported spot price was $23.00 (US) per pound, down $3.70 (US) from the previous quarter. The reported total spot market volume for the first nine months of 2016 was 32 million pounds, compared to 36 million pounds over the same period in 2015.

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. The volume of long-term contracting continued to be low, reported by UxC to be approximately 38 million pounds for the first nine months of 2016, compared to approximately 56 million pounds over the same period in 2015. The average reported long-term price at the end of the quarter was $37.50 (US) per pound, down $3.00 (US) from the previous quarter.

Spot and long-term UF₆ conversion prices also declined during the quarter.

Shares and stock options outstanding

At October 31, 2016, we had:

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

• 8,083,104 stock options outstanding, with exercise prices ranging from $16.38 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.

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Financial results

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

Consolidated financial results

CONSOLIDATED HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)		THREE MONTHS ENDED SEPTEMBER 30												NINE MONTHS ENDED SEPTEMBER 30
		2016				2015				CHANGE				2016				2015				CHANGE
Revenue			670				649				3	%			1,544				1,779				(13	)%
Gross profit			146				133				10	%			307				415				(26	)%
Net earnings (losses) attributable to equity holders			142				(4	)			>100	%			83				75				11	%
$ per common share (basic)			0.36				(0.01	)			>100	%			0.21				0.19				11	%
$ per common share (diluted)			0.36				(0.01	)			>100	%			0.21				0.19				11	%
Adjusted net earnings (non-IFRS, see page 7)			118				78				51	%			54				193				(72	)%
$ per common share (adjusted and diluted)			0.30				0.20				50	%			0.14				0.49				(71	)%
Cash provided by (used in) operations (after working capital changes)			385				(121	)			>100	%			57				(53	)			>100	%

NET EARNINGS

Net earnings attributable to equity holders this quarter were $142 million ($0.36 per share diluted) compared to net losses of $4 million (losses of $0.01 per share diluted) in the third quarter of 2015 due to:

• lower mark-to-market losses on foreign exchange derivatives compared to the third quarter of 2015

• gain from termination of long-term contracts

• higher gross profit from our uranium segment

partially offset by:

• lower foreign exchange gains

• lower gross profit from our NUKEM segment

• lower tax recovery

On an adjusted basis, our earnings this quarter were $118 million ($0.30 per share diluted) compared to earnings of $78 million ($0.20 per share diluted) (non-IFRS measure, see page 7) in the third quarter of 2015. The change was mainly due to:

• gain from termination of long-term contracts

• higher gross profit from our uranium segment

• higher tax recovery

partially offset by:

• higher losses on foreign exchange derivatives designated for use in the period compared to the third quarter of 2015

• lower foreign exchange gains

• lower gross profit from our NUKEM segment

See Financial results by segment on page 17 for more detailed discussion.

FIRST NINE MONTHS

Net earnings attributable to equity holders in the first nine months of the year were $83 million ($0.21 per share diluted) compared to earnings of $75 million ($0.19 per share diluted) in the first nine months of 2015 mainly due to:

• higher gross profit from our fuel services segment

• mark-to-market gains on foreign exchange derivatives compared to losses in the first nine months of 2015

• gain from termination of long-term contracts

partially offset by:

• impairment of our Rabbit Lake operation

• lower gross profit from our uranium and NUKEM segments

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• higher administration costs

• higher exploration costs

• higher foreign exchange losses compared to gains in the first nine months of 2015

• lower tax recovery

On an adjusted basis, our earnings for the first nine months of this year were $54 million ($0.14 per share diluted) compared to earnings of $193 million ($0.49 per share diluted) (non-IFRS measure, see page 7) for the first nine months of 2015. Key variances include:

• lower gross profit from our uranium and NUKEM segments

• higher administration costs

• higher exploration costs

• higher foreign exchange losses compared to gains in the first nine months of 2015

partially offset by:

• higher gross profit from our fuel services segment

• gain from termination of long-term contracts

• higher tax recovery

See Financial results by segment on page 17 for more detailed discussion.

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 adjustments, Rabbit Lake reclamation provisions, impairment charges, write off of assets, and income taxes on adjustments.

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 SEPTEMBER 30								NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)		2016				2015				2016				2015
Net earnings (losses) attributable to equity holders			142				(4	)			83				75
Adjustments
Adjustments on foreign exchange derivatives			(27	)			112				(153	)			157
NUKEM purchase price inventory adjustment			—				—				(6	)			(3	)
Impairment charges			—				—				124				6
Rabbit Lake reclamation provision			(6	)			—				(6	)			—
Income taxes on adjustments			9				(30	)			12				(42	)
Adjusted net earnings			118				78				54				193

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The following table shows what contributed to the change in adjusted net earnings for this quarter and for the first nine months of the year.

				THREE MONTHS				NINE MONTHS
($ MILLIONS)				ENDED SEPTEMBER 30				ENDED SEPTEMBER 30
Adjusted net earnings – 2015					78				193
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))
Uranium		Higher (lower) sales volume			36				(24	)
		Lower realized prices ($US)			—				(31	)
		Foreign exchange impact on realized prices			5				56
		Lower (higher) costs			2				(50	)
		change – uranium			43				(49	)
Fuel services		Lower sales volume			(1	)			(2	)
		Higher realized prices ($Cdn)			—				8
		Higher costs			—				(2	)
		change – fuel services			(1	)			4
NUKEM		Gross profit			(28	)			(64	)
		change – NUKEM			(28	)			(64	)
Other changes
Lower (higher) administration expenditures					1				(19	)
Higher exploration expenditures					—				(4	)
Higher income tax recovery					14				34
Gain on customer contract settlements					59				59
Higher loss on disposal of assets					(1	)			(9	)
Higher loss on derivatives					(24	)			(9	)
Higher foreign exchange losses					(21	)			(75	)
Other					(2	)			(7	)
Adjusted net earnings – 2016					118				54

See Financial results by segment on page 17 for more detailed discussion.

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)		2016												2015																2014
		Q3				Q2				Q1				Q4				Q3				Q2				Q1				Q4
Revenue			670				466				408				975				649				565				566				889
Net earnings (losses) attributable to equity holders			142				(137	)			78				(10	)			(4	)			88				(9	)			73
$ per common share (basic)			0.36				(0.35	)			0.20				(0.03	)			(0.01	)			0.22				(0.02	)			0.18
$ per common share (diluted)			0.36				(0.35	)			0.20				(0.03	)			(0.01	)			0.22				(0.02	)			0.18
Adjusted net earnings (losses) (non-IFRS, see page 7)			118				(57	)			(7	)			151				78				46				69				205
$ per common share (adjusted and diluted)			0.30				(0.14	)			(0.02	)			0.38				0.20				0.12				0.18				0.52
Cash provided by (used in) operations (after working capital changes)			385				(51	)			(277	)			503				(121	)			(65	)			134				236

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 79% of consolidated revenues in the third quarter of 2016

• 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

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• 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 7 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 ($ MILLIONS EXCEPT PER SHARE AMOUNTS)		2016												2015																2014
		Q3				Q2				Q1				Q4				Q3				Q2				Q1				Q4
Net earnings (losses) attributable to equity holders			142				(137	)			78				(10	)			(4	)			88				(9	)			73
Adjustments
Adjustments on foreign exchange derivatives			(27	)			(10	)			(116	)			10				112				(57	)			101				10
NUKEM purchase price inventory adjustment			—				(6	)			—				—				—				—				(3	)			(4	)
Impairment charges			—				124				—				210				—				—				6				131
Rabbit Lake reclamation provision			(6	)			—				—				—				—				—				—				—
Write-off of assets			—				—				—				—				—				—				—				41
Income taxes on adjustments			9				(28	)			31				(59	)			(30	)			15				(26	)			(46	)
Adjusted net earnings (losses) (non-IFRS, see page 7)			118				(57	)			(7	)			151				78				46				69				205

Corporate expenses

ADMINISTRATION

		THREE MONTHS ENDED SEPTEMBER 30												NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)		2016				2015				CHANGE				2016				2015				CHANGE
Direct administration			39				38				3	%			145				122				19	%
Stock-based compensation			—				2				(100	)%			6				10				(40	)%
Total administration			39				40				(3	)%			151				132				14	%

Direct administration costs were $1 million higher for the third quarter of 2016 compared to the same period last year, and $23 million higher for the first nine months. The increase was mainly due to:

• one-time costs related to collaboration agreements

• charges related to the consolidation of office space

• legal costs as our CRA dispute progresses towards trial

• restructuring of our NUKEM segment, and corporate office changes resulting from operational changes at Rabbit Lake and our US ISR operations

We have reduced staffing levels at our corporate office by 10% to date in 2016, and we are continuing to evaluate corporate support functions in light of the operational changes at our Rabbit Lake and US ISR operations, and the continued weak market conditions.

EXPLORATION

In the third quarter, uranium exploration expenses were $10 million, unchanged from the third quarter of 2015. Exploration expenses for the first nine months of the year increased by $4 million compared to 2015, to $37 million, due to a planned increase in expenditures.

INCOME TAXES

We recorded an income tax recovery of $10 million in the third quarter of 2016, compared to $35 million in the third quarter of 2015.

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On an adjusted basis, we recorded an income tax recovery of $19 million this quarter compared to $5 million in the third quarter of 2015 primarily due to a change in the distribution of earnings among foreign jurisdictions. In 2016, we recorded losses of $121 million in Canada compared to $115 million in 2015, while earnings in foreign jurisdictions increased to $221 million from $187 million.

In the first nine months of 2016, we recorded an income tax recovery of $66 million compared to $85 million in 2015.

On an adjusted basis, we recorded an income tax recovery of $79 million for the first nine months compared to $45 million in 2015 due to lower pre-tax adjusted earnings in 2016. We recorded losses of $22 million during the first nine months compared to earnings of $147 million for the same period in 2015.

		THREE MONTHS ENDED SEPTEMBER 30								NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)		2016				2015				2016				2015
Pre-tax adjusted earnings1
Canada2			(121	)			(115	)			(371	)			(382	)
Foreign			221				187				349				529
Total pre-tax adjusted earnings			100				72				(22	)			147
Adjusted income taxes1
Canada2			(28	)			(26	)			(96	)			(86	)
Foreign			9				21				17				41
Adjusted income tax recovery			(19	)			(5	)			(79	)			(45	)

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 7).

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with CRA since 2008, when they originated, and with the 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 2010, CRA has shifted CEL’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2010, transfer pricing penalties. The IRS is also proposing to allocate a portion of CEL’s income for the years 2009 through 2012 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $320 million for the 2003 – 2015 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. To date, we have received notices of reassessment for our 2003 through 2010 tax returns. We have recorded a cumulative tax provision of $54 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 September 30, 2016. 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.

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For the years 2003 through 2010, CRA issued notices of reassessment for approximately $3.4 billion of additional income for Canadian tax purposes, which would result in a related tax expense of approximately $1.1 billion. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2010 in the amount of $292 million. The Canadian income tax rules include provisions that require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions, we have paid a net amount of $264 million cash. In addition, we have provided $340 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed to date. The amounts paid or secured are shown in the table below.

YEAR PAID ($ MILLIONS)		CASH TAXES				INTEREST AND INSTALMENT PENALTIES				TRANSFER PRICING PENALTIES				TOTAL				CASH REMITTANCE				SECURED BY LC
Prior to 2013			—				13				—				13				13				—
2013			1				9				36				46				46				—
2014			106				47				—				153				153				—
2015			202				71				79				352				20				332
2016			7				2				31				40				32				8
Total			316				142				146				604				264				340

Using the methodology we believe CRA will continue to apply, and including the $3.4 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $7.4 billion of additional income taxable in Canada for the years 2003 through 2015, which would result in a related tax expense of approximately $2.2 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2010. As a result, we estimate that cash taxes and transfer pricing penalties for all years would be between $1.5 billion and $1.7 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 $750 million and $850 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. In 2015, the CRA decided to disallow the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This does not impact the anticipated income tax expense for a particular year, but does impact the timing of any required security or payment. For the 2010 tax year, as an alternative to paying cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. We expect to be able to continue to provide security in the form of letters of credit to satisfy these requirements. The estimated amounts summarized in the table below reflect actual amounts paid or secured and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2015, and include the expected timing adjustment for the inability to use any loss carry-backs starting in 2008. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2015.

$ MILLIONS		2003-2015				2016-2017				2018-2023				TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period
Cash payments			156				105 - 130				100 - 125				360 - 410
Secured by letters of credit			264				40 - 65				85 - 110				390 - 440
Total paid1			420				145 - 195				185 - 235				750 - 850

¹  These amounts do not include interest and instalment penalties, which totalled approximately $142 million to September 30, 2016.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $604 million already paid or otherwise secured to date.

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The trial for the 2003, 2005 and 2006 reassessments commenced in October 2016. Final arguments are expected in the second half of 2017. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

We have received Revenue Agents Reports (RAR) from the IRS for the tax years 2009 to 2012. The IRS is challenging the transfer pricing used under certain intercompany transactions pertaining to the 2009 to 2012 tax years for certain of our US subsidiaries. The 2009 to 2012 RARs list the adjustments proposed by the IRS and calculate 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 earned by Cameco Inc., one of our US subsidiaries, is inadequate

The proposed adjustments result in an increase in taxable income in the US of approximately $419 million (US) and a corresponding increased income tax expense of approximately $122 million (US) for the 2009 through 2012 taxation years, with interest being charged thereon. In addition, the IRS proposed cumulative penalties of approximately $8 million (US) in respect of the adjustment.

We believe that the conclusions of the IRS in the RARs are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. 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 the IRS 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 2011 through 2015 using a similar methodology as for the years 2003 through 2010, and the reassessments will be issued on the basis we expect

• we will be able to apply elective deductions and utilize letters of credit to the extent anticipated

• CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years 2007 through 2010) in addition to interest charges and instalment penalties

• we will be substantially successful in our dispute with CRA and the cumulative tax provision of $54 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

• IRS may propose adjustments for later years subsequent to 2012

• 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 2011 through 2015 using a different methodology than for years 2003 through 2010, or we are unable to utilize elective deductions or letters of credit to the extent anticipated, resulting in the required cash payments or security provided 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 2013 through 2015 using a different methodology than for 2009 through 2012

• we are unable to effectively eliminate all double taxation

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FOREIGN EXCHANGE

At September 30, 2016:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.31 (Cdn), up from $1.30 at June 30, 2016. The exchange rate averaged $1.00 (US) for $1.30 (Cdn) over the quarter.

• We had foreign currency forward contracts of $0.9 billion (US) and foreign currency options of $120 million (US). The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.29 (Cdn), US currency option contracts had an average exchange rate range of $1.00 (US) for $1.29 to $1.34 (Cdn).

• The mark-to-market loss on all foreign exchange contracts was $15 million, compared to a $16 million loss at June 30, 2016.

Outlook for 2016

Our outlook for 2016 reflects the expenditures necessary to help us achieve our strategy. Our outlook for NUKEM revenue and gross profit, fuel services average unit cost of sales, consolidated revenue, consolidated tax rate, and capital expenditures has changed. We do not provide an outlook for the items in the table that are marked with a dash.

See 2016 Financial results by segment on page 17 for details.

2016 FINANCIAL OUTLOOK

CONSOLIDATED

URANIUM

FUEL SERVICES

NUKEM

Production

—

25.8 million lbs

8 to 9 million kgU

—

Delivery volume1

—

30 to 32 million lbs2

Decrease up to 5%

7 to 8 million lbs U3O8

Revenue compared to 20153

Decrease 10% to 15%

Decrease 5% to 10%4

Increase up to 5%

Decrease 20% to 25%

Average unit cost of sales (including D&A)

—

Increase up to 5% 5

Increase 5% to 10%

—

Direct administration costs compared to 20156

Increase 10% to 15%

—

—

—

Gross profit

—

—

—

Gross profit 1% to 2% 7

Exploration costs compared to 2015

—

Increase 15% to 20%

—

—

Tax rate8

Recovery of > 200%

—

—

—

Capital expenditures

$245 million

—

—

—

¹ Our 2016 outlook for delivery volume does not include sales between our uranium, fuel services and NUKEM segments.

² Our uranium delivery volume is based on the volumes we currently have commitments to deliver under contract in 2016.

³  For comparison of our 2016 outlook and 2015 results for revenue, we do not include sales between our uranium, fuel services and NUKEM segments.

⁴  Based on a uranium spot price of $18.75 (US) per pound (the Ux spot price as of October 31, 2016), a long-term price indicator of $36.00 (US) per pound (the Ux long-term indicator on October 31, 2016) and an exchange rate of $1.00 (US) for $1.30 (Cdn).

⁵  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in the remainder of 2016, then we expect the overall unit cost of sales could be different.

⁶  Direct administration costs do not include stock-based compensation expenses. See page 9 for more information.

⁷  NUKEM gross profit is net of inventory write-downs.

⁸  Our outlook for the tax rate is based on adjusted net earnings.

We have reduced our outlook for NUKEM revenue to a decrease of 20% to 25% (previously a decrease of 5% to 10%) due to a continued decrease in the spot price. As a result, our outlook for consolidated revenue has also changed to a decrease of 10% to 15% (previously a decrease of 5% to 10%). We have also recast our outlook for NUKEM gross profit to be 1% to 2%, net of inventory write-downs (NUKEM gross profit was previously shown as up to 1%, including inventory write-downs).

Average unit cost of sales in our fuel services segment is now expected to increase 5% to 10% (previously an increase of 10% to 15%) due to an overall decrease in production costs and the mix of products sold.

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Our outlook for capital expenditures has decreased to $245 million (previously $275 million) due to a reduction in spending at McArthur River, as well as the timing of expenditures on projects in our fuel services segment.

We have adjusted our outlook for consolidated tax rate to a recovery of greater than 200% (previously 175% to 200%). The increase in expected recovery is due to the changes in our outlook noted above, which result in a change in the distribution of earnings between jurisdictions, as well as the effect of losses recognized in Canada offset by foreign income.

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. We are on track to meet our 2016 uranium sales targets, and, therefore, expect to deliver between 10 million and 12 million pounds in the fourth quarter.

REVENUE, CASH FLOW AND EARNINGS SENSITIVITY ANALYSIS

For the rest of 2016:

• an increase or decrease of $5 (US) per pound in both the Ux spot price ($18.75 (US) per pound on October 31, 2016) and the Ux long-term price indicator ($36.00 (US) per pound on October 31, 2016) would increase or decrease revenue by $7 million and net earnings by $5 million.

• a one-cent change in the value of the Canadian dollar versus the US dollar would change adjusted net earnings by $3 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. Cash flow would change by $1 million, with a decrease in the value of the Canadian dollar versus the US dollar having a negative 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 September 30, 2016 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 September 30, 2016 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
2016			41				41				42				44				46				48				49
2017			38				45				56				67				78				87				95
2018			39				47				58				69				80				89				97
2019			38				47				59				70				80				88				95
2020			41				48				59				69				78				86				92

URANIUM PRICE SENSITIVITY

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The table and graph illustrate the mix of long-term contracts in our September 30, 2016 portfolio, and are consistent with our marketing strategy. Both have been updated to September 30, 2016 to reflect deliveries made and contracts entered into or terminated.

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 higher prices or have high floor prices will yield prices that are higher than current market prices.

In today’s weak market environment, the strength of our contract portfolio has been tested and proven to be sound. In cases where a customer is seeking relief due to a challenging policy, operating or economic environment, we evaluate their specific circumstances to determine if uncertain future value can be converted into certain present value.

In the third quarter, our evaluation resulted in agreements to terminate long-term supply contracts with two of our utility customers where future uranium requirements were uncertain. In both instances, we were able to harvest that uncertain future value to improve earnings and cash flow in the near-term. The first, which we disclosed as a subsequent event in our second quarter MD&A, had product deliveries from 2016 through 2021 and resulted in a gain on contract settlement of $46.7 million. The second had product deliveries from 2016 through 2020 and resulted in a contract settlement of $12.3 million. These gains have been reflected in our financial results for the third quarter as other income.

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 27 million pounds per year, with commitment levels in 2016 through 2018 higher than in 2019 and 2020

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

Deliveries

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

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 our tier-one production capacity and flexibility over the next several years. We have a number of alternatives to fund future capital requirements, including 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. We expect our cash balances and operating cash flows to meet our capital requirements for the remainder of 2016.

We have an ongoing transfer pricing dispute with CRA. See page 10 for more information. Until this dispute is settled, we expect to pay cash or provide security in the form of letters of credit for future amounts owing to the Government of Canada for 50% of the cash taxes payable and the related interest and penalties.

CASH FROM OPERATIONS

Cash provided by operations was $506 million higher this quarter than in the third quarter of 2015. Contributing to this change was a decrease in working capital requirements, which required $394 million less in 2016 than in 2015. In the third quarter of 2016, inventories declined; however in 2015, there was an increase in inventory, which required more working capital. In addition, there was a large increase in accounts receivable in 2015 compared to the current quarter, which also required more working capital. Not including working capital requirements, our operating cash flows this quarter were higher by $112 million.

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Cash provided by operations was $110 million higher in the first nine months of 2016 than for the same period in 2015 due largely to a decrease in working capital requirements. This was a result of the increase in inventory being higher in 2015 compared to the current period. Working capital required $168 million less in 2016. Partially offsetting the decreased working capital requirements were lower gross profits in our operating segments. Not including working capital requirements, our operating cash flows in the first nine months were lower by $58 million.

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.7 billion at September 30, 2016, unchanged from June 30, 2016. At September 30, 2016, we had approximately $1.4 billion outstanding in letters of credit, unchanged from June 30, 2016. At September 30, 2016, we had no short-term debt outstanding on our $1.25 billion unsecured revolving credit facility, down from $235 million on June 30, 2016, and during the quarter, we extended the maturity date of the facility from November 1, 2019, to November 1, 2020. At September 30, 2016, NUKEM had $26 million ($20 million (US)) outstanding on their 75 million (€) multicurrency revolving loan facility in the form of a short-term loan, compared to nil on June 30, 2016.

Long-term contractual obligations

Since December 31, 2015, there have been no material changes to our long-term contractual obligations. Please see our annual MD&A for more information.

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 September 30, 2016, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2016 to be constrained by them.

NUKEM financing arrangements

NUKEM enters into financing arrangements with third parties where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (see notes 5 and 7 to the financial statements for more information). In addition, NUKEM is required to pledge the underlying inventory as security against these performance obligations. As of September 30, 2016, we had $4.8 million ($3.6 million (US)) of inventory pledged as security under financing arrangements, compared with $97.9 million ($70.8 million (US)) at December 31, 2015.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at September 30, 2016:

• purchase commitments

• financial assurances

• other arrangements

There have been no material changes to our purchase commitments since June 30, 2016. Please see our second quarter MD&A for more information.

Financial assurances

At September 30, 2016, our financial assurances totalled $1.4 billion, unchanged from June 30, 2016.

Other arrangements

We continue to use factoring and other third party arrangements to manage short-term cash flow fluctuations. You can read more about these arrangements in our 2015 annual MD&A.

16    CAMECO CORPORATION

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BALANCE SHEET

($ MILLIONS)		SEP 30, 2016				DEC 31, 2015				CHANGE
Cash and cash equivalents			199				459				(57	)%
Total debt			1,519				1,492				2	%
Inventory			1,388				1,285				8	%

Total cash and cash equivalents at September 30, 2016 were $199 million, or 57% lower than at December 31, 2015, primarily due to capital expenditures of $167 million, dividend payments of $119 million, and interest payments of $50 million, offset by cash provided by operations of $57 million and short-term borrowings of $26 million. Net debt at September 30, 2016 was $1,320 million.

Total product inventories increased to $1,388 million, including NUKEM’s inventories ($142 million). Inventories increased as sales were lower than production and purchases in the first nine months of the year. As of September 30, 2016, we held an inventory of 31 million pounds of U₃O₈ equivalent in our uranium segment (excluding broken ore).

Financial results by segment

Uranium

						THREE MONTHS ENDED SEPTEMBER 30												NINE MONTHS ENDED SEPTEMBER 30
HIGHLIGHTS						2016				2015				CHANGE				2016				2015				CHANGE
Production volume (million lbs)							5.9				8.2				(28	)%			19.9				18.7				6	%
Sales volume (million lbs)1							9.3				6.9				35	%			19.9				21.2				(6	)%
Average spot price		($	US/lb	)			24.57				36.21				(32	)%			27.86				36.91				(25	)%
Average long-term price		($	US/lb	)			37.83				44.17				(14	)%			41.06				47.06				(13	)%
Average realized price		($	US/lb	)			43.37				43.61				(1	)%			42.92				44.57				(4	)%
		($	Cdn/lb	)			56.34				56.07				—				56.77				55.65				2	%
Average unit cost of sales (including D&A)		($	Cdn/lb	)			39.97				40.16				—				41.63				39.13				6	%
Revenue ($ millions)1							526				388				36	%			1,129				1,179				(4	)%
Gross profit ($ millions)							153				110				39	%			301				350				(14	)%
Gross profit (%)							29				28				4	%			27				30				(10	)%

¹  There were no significant intersegment transactions in the periods shown.

THIRD QUARTER

Production volumes this quarter were 28% lower compared to the third quarter of 2015, mainly due to planned lower production from McArthur River/Key Lake and Rabbit Lake, and lower production from Inkai. See Uranium 2016 Q3 updates starting on page 21 for more information.

The 36% increase in uranium revenues was a result of a 35% increase in sales volume. Sales in the third quarter were higher than in 2015 due to the timing of deliveries, which are driven by customer requests and can vary significantly.

The US dollar average realized price decreased by 1% compared to 2015, mainly due to lower prices on market-related contracts, while the higher Canadian dollar realized prices this quarter were a result of the weakening of the Canadian dollar compared to 2015. This quarter, the exchange rate on the average realized price was $1.00 (US) for $1.30 (Cdn) compared to $1.00 (US) for $1.29 (Cdn) in the third quarter of 2015.

Total cost of sales (including D&A) increased by 34% ($373 million compared to $278 million in 2015) due to a 35% increase in sales volume.

The net effect was a $43 million increase in gross profit for the quarter.

FIRST NINE MONTHS

Production volumes for the first nine months of the year were 6% higher than in the previous year due to the addition of production from Cigar Lake and higher production at Inkai, partially offset by planned lower production at McArthur River/Key Lake, Rabbit Lake and our US operations. See Uranium 2016 Q3 updates starting on page 21 for more information.

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Uranium revenues decreased 4% compared to the first nine months of 2015 due to a 6% decrease in sales volumes, partially offset by a 2% increase in the Canadian dollar average realized price.

Our Canadian dollar realized prices for the first nine months of 2016 were higher than 2015, primarily as a result of the weakening of the Canadian dollar compared to 2015. For the first nine months of 2016, the exchange rate on the average realized price was $1.00 (US) for $1.32 (Cdn) compared to $1.00 (US) for $1.25 (Cdn) for the same period in 2015.

Total cost of sales (including D&A) remained virtually unchanged ($828 million compared to $829 million in 2015) mainly due to a 6% decrease in sales volume for the first nine months, offset by a 6% increase in the unit cost of sales. The increase in the unit cost of sales was mainly the result of care and maintenance costs and severance costs related to the curtailment of production at Rabbit Lake and in the US.

The net effect was a $49 million decrease in gross profit for the first nine months.

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 care and maintenance costs, 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 SEPTEMBER 30												NINE MONTHS ENDED SEPTEMBER 30
($CDN/LB)		2016				2015				CHANGE				2016				2015				CHANGE
Produced
Cash cost			16.31				17.56				(7	)%			17.72				22.97				(23	)%
Non-cash cost			13.07				9.53				37	%			12.18				11.79				3	%
Total production cost			29.38				27.09				8	%			29.90				34.76				(14	)%
Quantity produced (million lbs)			5.9				8.2				(28	)%			19.9				18.7				6	%
Purchased
Cash cost			39.91				47.19				(15	)%			48.91				46.83				4	%
Quantity purchased (million lbs)			0.5				2.7				(81	)%			6.2				9.3				(33	)%
Totals
Produced and purchased costs			30.20				32.07				(6	)%			34.42				38.77				(11	)%
Quantities produced and purchased (million lbs)			6.4				10.9				(41	)%			26.1				28.0				(7	)%

The average cash cost of production was 7% lower for the quarter and 23% lower in the first nine months than in comparable periods in 2015. The change was primarily due to the rampup of low-cost production from Cigar Lake, and the impact of our second quarter actions to curtail higher cost production in the US and from Rabbit Lake.

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the third quarter, the average cash cost of purchased material was $39.91 (Cdn) per pound, or $30.75 (US) per pound in US dollar terms, compared to $37.78 (US) per pound in the third quarter of 2015. For the first nine months, the average cash cost of purchased material was $48.91 (Cdn), or $35.70 (US) per pound, compared to $37.51 (US) per pound in the same period in 2015.

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 third quarter and the first nine months of 2016 and 2015.

18    CAMECO CORPORATION

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Cash and total cost per pound reconciliation

		THREE MONTHS ENDED SEPTEMBER 30								NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)		2016				2015				2016				2015
Cost of product sold			285.7				205.5				654.6				660.9
Add / (subtract)
Royalties			(37.4	)			(31.3	)			(77.3	)			(67.0	)
Care and maintenance and severance costs			(20.1	)			—				(58.8	)			—
Other selling costs			(5.6	)			(1.9	)			(8.5	)			(7.1	)
Change in inventories			(106.4	)			99.1				145.9				278.1
Cash operating costs (a)			116.2				271.4				655.9				864.9
Add / (subtract)
Depreciation and amortization			87.6				72.2				173.1				168.2
Change in inventories			(10.5	)			6.0				69.3				52.5
Total operating costs (b)			193.3				349.6				898.3				1,085.6
Uranium produced & purchased (million lbs) (c)			6.4				10.9				26.1				28.0
Cash costs per pound (a ÷ c)			18.16				24.90				25.13				30.89
Total costs per pound (b ÷ c)			30.20				32.07				34.42				38.77

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

						THREE MONTHS ENDED SEPTEMBER 30												NINE MONTHS ENDED SEPTEMBER 30
HIGHLIGHTS						2016				2015				CHANGE				2016				2015				CHANGE
Production volume (million kgU)							0.6				0.6				—				6.5				6.3				3	%
Sales volume (million kgU)1							3.5				3.8				(8	)%			8.7				9.1				(4	)%
Average realized price		($	Cdn/kgU	)			22.09				22.22				(1	)%			25.06				24.11				4	%
Average unit cost of sales (including D&A)		($	Cdn/kgU	)			18.62				18.75				(1	)%			19.98				19.71				1	%
Revenue ($ millions)1							77				83				(7	)%			217				220				(1	)%
Gross profit ($ millions)							12				13				(8	)%			44				40				10	%
Gross profit (%)							16				16				—				20				18				11	%

¹  Includes sales and revenue between our fuel services and NUKEM segments (65,000 kgU in sales and revenue of $0.5 million in Q3 2016, nil in Q3 2015; 65,000 kgU in sales and revenue of $0.5 million in the first nine months of 2016, nil in the first nine months of 2015).

THIRD QUARTER

Total revenue for the third quarter of 2016 decreased to $77 million from $83 million for the same period last year. This was primarily due to an 8% decrease in sales volumes compared to 2015.

The total cost of products and services sold (including D&A) decreased by 7% ($65 million compared to $70 million in the third quarter of 2015) due to the decrease in sales volumes and a decrease in the average unit cost of sales. When compared to 2015, the average unit cost of sales was 1% lower.

The net effect was a $1 million decrease in gross profit.

FIRST NINE MONTHS

In the first nine months of the year, total revenue decreased by 1% due to a 4% decrease in sales volumes, partially offset by a 4% increase in realized price that was the result of the weakening Canadian dollar and the mix of products sold.

The total cost of products and services sold (including D&A) decreased 4% ($173 million compared to $180 million in 2015) due to the 4% decrease in sales volume, partially offset by a 1% increase in the average unit cost of sales.

The net effect was a $4 million increase in gross profit.

2016 THIRD QUARTER REPORT    19

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NUKEM

						THREE MONTHS ENDED SEPTEMBER 30												NINE MONTHS ENDED SEPTEMBER 30
HIGHLIGHTS						2016				2015				CHANGE				2016				2015				CHANGE
Uranium sales (million lbs)1							1.5				2.9				(48	)%			4.0				6.9				(42	)%
Average realized price		($	Cdn/lb	)			43.52				52.70				(17	)%			48.89				46.97				4	%
Cost of product sold (including D&A)2							82				170				(52	)%			224				326				(31	)%
Revenue ($ millions)1, 2							67				183				(63	)%			198				361				(45	)%
Gross profit (loss) ($ millions)2							(15	)			13				>(100	%)			(26	)			35				>(100	%)
Gross profit (loss) (%)2							(22	)			7				>(100	%)			(13	)			10				>(100	%)

¹  Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in Q3 2016, 130,000 pounds in sales and revenue of $6.0 million in Q3 2015); (nil in the first nine months of 2016, 873,000 pounds in sales and revenue of $19.3 million in the first nine months of 2015).

²  Includes U₃O₈, UF₆, and SWU.

THIRD QUARTER

During the third quarter of 2016, NUKEM delivered 1.5 million pounds of uranium, a decrease of 48% from the same period last year due largely to the timing of customer requirements. The majority of the deliveries in the quarter were under existing long-term contracts with utilities. Activity in the spot market continued to be light, as was the case in the first two quarters. Total revenues decreased by 63% as a result of lower sales volumes.

NUKEM recorded a gross loss of $15 million in the third quarter of 2016, compared to a $13 million gross profit in the third quarter of 2015. Included in the 2016 gross loss is a $12 million net write-down of inventory. The write-down was a result of a decline in the spot price during the period.

FIRST NINE MONTHS

During the nine months ended September 30, 2016, NUKEM delivered 4.0 million pounds of uranium, a decrease of 42%, due to very light market activity with a lack of profitable opportunities, and the timing of customer requirements. Total revenues decreased 45% due to a decrease in sales volumes, partially offset by a 4% increase in average realized price. The increase in realized price was mainly the result of deliveries under contracts negotiated in prior years when market prices were higher.

Gross profit percentage was a loss of 13% for the first nine months of 2016, a decrease from a profit of 10% in the same period in 2015. Included in the 2015 margin was a $3 million net recovery compared to a $26 million net write-down of inventory in 2016. The write-down in 2016 was a result of a decline in the spot price during the period.

The net effect was a $61 million decrease in gross profit.

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 28% lower than the third quarter of 2015. See below for more information.

URANIUM PRODUCTION

		THREE MONTHS ENDED SEPTEMBER 30								CHANGE				NINE MONTHS ENDED SEPTEMBER 30								CHANGE				2016 PLAN
OUR SHARE (MILLION LBS)		2016				2015								2016				2015
McArthur River/Key Lake			3.1				3.9				(21	)%			8.8				9.5				(7	)%			12.6
Cigar Lake			1.9				1.8				6	%			6.2				3.3				88	%			8.0
Inkai			0.6				1.0				(40	)%			2.8				2.2				27	%			3.0
Rabbit Lake			—				1.1				(100	)%			1.1				2.2				(50	)%			1.1
Smith Ranch-Highland			0.2				0.3				(33	)%			0.8				1.2				(33	)%			0.9
Crow Butte			0.1				0.1				—				0.2				0.3				(33	)%			0.2
Total			5.9				8.2				(28	)%			19.9				18.7				6	%			25.8

20    CAMECO CORPORATION

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Uranium 2016 Q3 updates

PRODUCTION UPDATE

McArthur River/Key Lake

Production for the third quarter was 21% lower compared to the same period last year due to a longer planned mill maintenance shut down. Production for the first nine months was slightly lower than last year due to lower planned annual production.

Cigar Lake

Total packaged production from Cigar Lake was 6% higher in the third quarter, and 88% higher in the first nine months compared to the same periods last year. The year-over-year increase is the result of the scheduled rampup of the operation.

Inkai

Production was 40% lower for the quarter and 27% higher for the first nine months compared to the same periods last year due to the timing of new wellfield development in our 2016 mine plan.

Smith Ranch-Highland/Crow Butte

At our US operations, total production was 25% lower for the quarter and 33% lower for the first nine months compared to the same periods in 2015, as a result of the decision to curtail production and defer all wellfield development beginning in May, 2016.

PRODUCTION CURTAILMENT

Rabbit Lake

The transition of the Rabbit Lake operation to care and maintenance was completed at the end of August, at a cost of $39.6 million. The site will remain in a safe care and maintenance state for the remainder of the year at a cost of about $15 million. Additionally, the total severance cost of $10.6 million is included in our cost of sales and reflected in our results.

We are continually weighing the value of maintaining the operation in standby, against the cost of doing so. However, as long as production is suspended, we expect care and maintenance costs to range between $35 million and $40 million annually for the first few years.

Fuel services 2016 Q3 updates    

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 0.6 million kgU in the third quarter, unchanged from the same period last year. Production in the first nine months was 3% higher than the same period in 2015.

Licensing

Our operating licence for the Port Hope Conversion Facility expires on February 29, 2017. The relicensing process with the Canadian Nuclear Safety Commission will begin in the fourth quarter.

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

• Greg Murdock, mine manager, McArthur River, Cameco

CIGAR LAKE

• Les Yesnik, general manager, Cigar Lake, Cameco

INKAI

• Darryl Clark, general director, JV Inkai

2016 THIRD QUARTER REPORT    21

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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 September 30, 2016, 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 September 30, 2016, 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 September 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

22    CAMECO CORPORATION