EX-99.3 4 d326339dex993.htm EX-99.3

EXHIBIT 99.3

Cameco Corporation

2016 Management’s Discussion and Analysis

February 9, 2017

Management’s discussion and analysis

February 9, 2017

| 6 |  |  | 2016 PERFORMANCE HIGHLIGHTS
| 9 |  |  | MARKET OVERVIEW AND 2016 DEVELOPMENTS
| 13 |  |  | OUR STRATEGY
| 20 |  |  | MEASURING OUR RESULTS
| 22 |  |  | FINANCIAL RESULTS
| 51 |  |  | OUR OPERATIONS AND PROJECTS
| 76 |  |  | MINERAL RESERVES AND RESOURCES
| 81 |  |  | ADDITIONAL INFORMATION

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2016. The information is based on what we knew as of February 8, 2017.

We encourage you to read our audited consolidated financial statements and notes as you review this MD&A. You can find more information about Cameco, including our 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, the Company 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 (US) 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 most recent annual information form, 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

• |  | our expectations about 2017 and future global uranium supply, consumption, demand, contracting volumes, number of reactors and nuclear generating capacity, including the discussion under the headings Market overview and 2016 developments

• |  | the discussion under the heading Our strategy

• |  | our 2017 objectives

• |  | our expectations for uranium deliveries in 2017

• |  | 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

• |  | the discussion of our expectations relating to our dispute with Tokyo Electric Power Company Holdings, Inc. (TEPCO)

• |  | our consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2017

• |  | our expectations for future tax payments and rates, including effective tax rates

• |  | our expectations for future royalty payments

• |  | our price sensitivity analysis for our uranium segment

• |  | our expectation that existing cash balances and operating cash flows will meet our anticipated 2017 capital requirements without the need for any significant additional funding, other than temporary drawings on short-term liquidity during the course of the year

• |  | our expectations for 2017, 2018 and 2019 capital expenditures

• |  | our expectation that in 2017 we will be able to comply with all the covenants in our unsecured revolving credit facility

• |  | our future plans and expectations for each of our uranium operating properties and projects under evaluation, and fuel services operating sites

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

• |  | our mineral reserve and resource estimates

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 our cost reduction strategies are unsuccessful, 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 or with TEPCO

• |  | we are unsuccessful in our dispute with Canada Revenue Agency (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 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, including AREVA’s renewal of the McClean Lake mill’s operating licence, and our renewal of the Port Hope conversion facility’s operating licence

• |  | 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

2 |  | CAMECO CORPORATION |  |

• |  | 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, or our uranium purchasers fail to fulfil purchase 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 for any reason

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

• |  | our expectations relating to Rabbit Lake care and maintenance costs prove to be inaccurate

• |  | 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, unanticipated consequences of our cost reduction strategies, or other development and operating risks

Material assumptions

• |  | our expectations regarding sales and purchase volumes and prices for uranium and fuel services, and that the counterparties to our sales and purchase agreements will honour their commitments

• |  | 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, including our expectations regarding the success of our cost reduction strategies

• |  | 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 and with TEPCO

• |  | 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, including AREVA’s renewal of the McClean Lake mill’s operating licence, and our renewal of the Port Hope conversion facility’s operating licence

• |  | 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, unanticipated consequences of our cost reduction strategies, or other development or operating risks

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 3

Our business
We are one of the world’s largest uranium producers, with uranium assets on three continents. Nuclear energy plants around the world use our uranium products to generate one of the cleanest sources of electricity available today. Our operations and investments span the nuclear fuel cycle, from exploration to fuel manufacturing.
Our head office is in Saskatoon, Saskatchewan.
URANIUM
Operations
We are one of the world’s largest uranium producers, and in 2016 accounted for about 17% of the world’s production. We have controlling ownership of the world’s largest high-grade reserves.
• Uranium Projects under Evaluation
We use a stage gate process to evaluate our uranium projects and will advance them at a pace aligned with market opportunities, in order to respond when the market signals a need for more uranium.
Uranium Exploration (grey shaded)
Our exploration program is directed at replacing mineral resources as they are depleted by our production. Our active programs are focused on three continents, where our land holdings total about 1.5 million hectares (areas where we hold land are highlighted).
FUEL SERVICES
We are an integrated uranium fuel supplier, offering refining, conversion and fuel manufacturing services. We control 25% of world conversion capacity.
MARKETING
We sell uranium and fuel services to nuclear utilities in 13 countries, with sales commitments to supply about 150 million pounds of U3O8 and over 50 million kilograms of UF6 conversion services.
NUKEM
NUKEM deals in the physical trading of uranium concentrates, conversion and enrichment services. Its trading strategy is nonspeculative and seeks to match quantities and pricing structures of long-term supply and delivery contracts, minimizing exposure to commodity price fluctuations and locking in profit margins.
OTHER FUEL CYCLE INVESTMENTS
ENRICHMENT
GE-Hitachi Global Laser Enrichment (GLE) is testing a third-generation technology that, if successful, will use lasers to commercially enrich uranium. We have a 24% interest in GLE, which is currently undergoing restructuring. Existing partners General Electric (51%) and Hitachi Ltd. (25%) have negotiated an arrangement providing Silex Systems Ltd. (the technology’s licensor), with an exclusive option on their interests.
* Operation suspended/curtailed due to current market conditions
4 CAMECO CORPORATION
Smith Ranch-Highland*
Crow Butte*
Corporate Office
Millennium
McArthur River/Key Lake
Cigar Lake
Rabbit Lake*
Cameco Inc.
Port Hope Blind River Cameco Fuel Manufacturing Inc.
NUKEM Inc.
GLE

Advantages
We are a pure-play nuclear fuel investment with a proven track record and the strengths to take advantage of the world’s rising demand for safe, clean and reliable energy.
With our extraordinary assets, long-term contract portfolio, employee expertise, comprehensive industry knowledge and financial strength, we are confident in our ability to increase shareholder value.
NUKEM GmbH
Cameco Europe Ltd.
Inkai
Yeelirrie
Kintyre
MANAGEMENT’S DISCUSSION AND ANALYSIS 5

2016 performance highlights

Our focus throughout 2016 was to lower our costs and improve efficiency amid difficult uranium market conditions. We continue to anticipate a market shift as demand increases in the form of restarts and new reactors, while current and future supply decreases through curtailments and lack of investment. However, until we see signs of that shift emerging, we will continue to take the necessary actions intended to preserve shareholder value and position the company for long term success.

Financial performance

HIGHLIGHTS |  |  |  |  |  |
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2016 |  |  | 2015 |  |  | CHANGE |
Revenue |  |  | 2,431 |  |  |  | 2,754 |  |  |  | (12 | )%
Gross profit |  |  | 463 |  |  |  | 697 |  |  |  | (34 | )%
Net earnings (loss) attributable to equity holders |  |  | (62 | ) |  |  | 65 |  |  |  | (195 | )%
$ per common share (diluted) |  |  | (0.16 | ) |  |  | 0.16 |  |  |  | (194 | )%
Adjusted net earnings (non-IFRS, see page 24) |  |  | 143 |  |  |  | 344 |  |  |  | (58 | )%
$ per common share (adjusted and diluted) |  |  | 0.36 |  |  |  | 0.87 |  |  |  | (59 | )%
Cash provided by operations (after working capital changes) |  |  | 312 |  |  |  | 450 |  |  |  | (31 | )%

Net earnings attributable to equity holders (net earnings) and adjusted net earnings were lower in 2016 compared to 2015. See 2016 consolidated financial results beginning on page 23 for more information.

Our uranium segment continued to outperform the market

In our uranium segment, we exceeded our annual production expectations, and realized a number of successes and new developments at our mining operations. Key highlights:

• |  | annual production of 27.0 million pounds—5% higher than the guidance provided in our 2016 third quarter MD&A

• |  | quarterly production of 7.1 million pounds in the fourth quarter—26% lower than in 2015 due to the suspension of production at Rabbit Lake, the curtailment of production at Cameco Resources’ US operations, and lower production at Inkai

• |  | exceeded planned production at the Cigar Lake mine and AREVA’s McClean Lake mill

• |  | we signed an agreement with our partner Kazatomprom and JV Inkai to restructure and enhance JV Inkai

• |  | higher-cost production was suspended at our Rabbit Lake operation and curtailed at Cameco Resources’ US ISR operations; by the end of August, 2016, Rabbit Lake was in a state of safe care and maintenance

• |  | we received conditional environmental approval for our Yeelirrie uranium project in Western Australia, and we were granted a 10-year extension of the requirement to provide the government with a development proposal

See Our operations and projects beginning on page 51 for more information.

Updates on our other segments and investments

Production in 2016 from our fuel services segment was 13% lower than in 2015. We continue to face weak market conditions for conversion services, and we are continuing to operate Port Hope at a reduced production level.

6 |  | CAMECO CORPORATION |  |

HIGHLIGHTS |  |  |  |  |  |  | 2016 |  |  | 2015 |  |  | CHANGE |
Uranium |  | Production volume (million lbs) |  |  |  |  |  |  | 27.0 |  |  |  | 28.4 |  |  |  | (5 | )%
|  | Sales volume (million lbs)1 |  |  |  |  |  |  | 31.5 |  |  |  | 32.4 |  |  |  | (3 | )%
|  | Average realized price |  | ($ | US/lb | ) |  |  | 41.12 |  |  |  | 45.19 |  |  |  | (9 | )%
|  |  |  | ($ | Cdn/lb | ) |  |  | 54.46 |  |  |  | 57.58 |  |  |  | (5 | )%
|  | Revenue ($ millions)1 |  |  |  |  |  |  | 1,718 |  |  |  | 1,866 |  |  |  | (8 | )%
|  | Gross profit ($ millions) |  |  |  |  |  |  | 444 |  |  |  | 608 |  |  |  | (27 | )%
Fuel services |  | Production volume (million kgU) |  |  |  |  |  |  | 8.4 |  |  |  | 9.7 |  |  |  | (13 | )%
|  | Sales volume (million kgU)1 |  |  |  |  |  |  | 12.7 |  |  |  | 13.6 |  |  |  | (7 | )%
|  | Average realized price |  | ($ | Cdn/kgU | ) |  |  | 25.37 |  |  |  | 23.37 |  |  |  | 9 | %
|  | Revenue ($ millions)1 |  |  |  |  |  |  | 321 |  |  |  | 319 |  |  |  | 1 | %
|  | Gross profit ($ millions) |  |  |  |  |  |  | 63 |  |  |  | 61 |  |  |  | 3 | %
NUKEM |  | Sales volume U3O8 (million lbs)1 |  |  |  |  |  |  | 7.1 |  |  |  | 10.7 |  |  |  | (34 | )%
|  | Average realized price |  | ($ | Cdn/lb | ) |  |  | 47.90 |  |  |  | 48.82 |  |  |  | (2 | )%
|  | Revenue ($ millions)1 |  |  |  |  |  |  | 391 |  |  |  | 554 |  |  |  | (29 | )%
|  | Gross profit (loss) ($ millions) |  |  |  |  |  |  | (28 | ) |  |  | 42 |  |  |  | (167 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments. Please see 2016 Financial results by segment beginning on page 42.

Industry prices

In 2016, the uranium spot price ranged from a high of $35 (US) per pound to a low of about $18 (US) per pound, averaging around $26 (US) for the year. Utilities continue to be well covered under existing contracts, and, given the current uncertainties in the market, we expect they and other market participants will continue to be opportunistic in their buying. As a result, contracting is expected to remain somewhat discretionary in 2017.

|  | 2016 |  |  | 2015 |  |  | CHANGE |
Uranium ($US/lb U3O8)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  | 25.64 |  |  |  | 36.55 |  |  |  | (30 | )%
Average annual long-term price |  |  | 39.00 |  |  |  | 46.29 |  |  |  | (16 | )%
Fuel services ($US/kgU as UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 6.40 |  |  |  | 7.35 |  |  |  | (13 | )%
Europe |  |  | 6.91 |  |  |  | 7.85 |  |  |  | (12 | )%
Average annual long-term price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 12.58 |  |  |  | 15.33 |  |  |  | (18 | )%
Europe |  |  | 13.56 |  |  |  | 16.38 |  |  |  | (17 | )%

Note: the industry does not publish UO2 prices.

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

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 7

Also of note

On January 31, 2017, Tokyo Electric Power Company Holdings, Inc. (“TEPCO”) confirmed that it would not accept a uranium delivery scheduled for February 1, 2017, and would not withdraw the contract termination notice it provided to Cameco Inc. on January 24, 2017 with respect to a uranium supply agreement between TEPCO and Cameco Inc. TEPCO alleged that an event of “force majeure” has occurred because it has been unable to operate its nuclear reactors for 18 consecutive months due to the Fukushima nuclear accident in March 2011 and the resulting government regulations. Cameco Inc. sees no basis for terminating the agreement and will pursue all its legal rights and remedies against TEPCO.

Under the agreement, TEPCO has already received and paid for 2.2 million pounds of uranium since 2014. The termination would affect approximately 9.3 million pounds of uranium deliveries through 2028, worth approximately $1.3 billion in revenue to Cameco, including about $126 million in each of 2017, 2018 and 2019 based on 855,000 pounds of deliveries in each of those years. All estimates and uranium volumes are provided on a consolidated basis for Cameco using expected contract prices and an exchange rate of $1.00 (US) for $1.30 (Cdn) and do not reflect any resale of the cancelled deliveries under the contract with TEPCO.

In this MD&A, our 2017 financial outlook and other disclosures relating to our contract portfolio are presented on a basis that excludes this agreement with TEPCO, which is under dispute.

SHARES AND STOCK OPTIONS OUTSTANDING

At February 7, 2017, we had:

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

• |  | 7,969,882 stock options outstanding, with exercise prices ranging from $16.38 to $54.38

DIVIDEND

Our board of directors has established a quarterly dividend of $0.10 ($0.40 per year) per common share. The dividend is reviewed quarterly based on our cash flow, earnings, financial position, strategy and other relevant factors.

8 |  | CAMECO CORPORATION |  |

Market overview and 2016 developments

Cautiously optimistic

Today’s uranium market is challenging, but we are cautiously optimistic that we are starting to see some of the signposts required for a market recovery. The future uncovered uranium requirements of utilities due to low levels of long-term contracting over the past four years are increasing. There have been several announcements on both the supply and demand side that are expected to have a positive impact on the challenging market, and there is renewed interest in nuclear power and uranium from non-traditional market participants. However, we believe it will ultimately be the return of term contracting in a significant way that will signal that market dynamics have turned more positive.

TODAY: A STORY OF OVERSUPPLY

The uranium market continues to be in a state of oversupply. Market recovery has taken longer than anticipated as a result of a slower than expected pace of reactor restarts in Japan, unexpected reactor shutdowns in other regions, delays in reactor construction programs, and reactors under construction not yet consuming uranium. At the same time, supply has continued to perform well, adding to the delay in market improvement.

On the supply side, secondary supplies, consisting largely of government inventories and enricher underfeeding, continue to provide the industry with an exceptionally low-cost source of uranium supply, where the economics differ considerably from mined production. Similarly, several producers, whose production drivers are not always economic, such as large diversified miners and companies mining uranium for strategic or social purposes, negatively impact the supply-demand balance. The lowest cost – tier-one – production, including our own assets, continues to perform well, with cash costs that allow them to remain economic, even at current prices. Finally, higher-cost production, though sensitive to the uranium price, continues to be supported by higher prices under long-term contracts and/or advantageous foreign exchange rates.

The excess supply has impacted the market in a significant way. Abundant spot material has been available to satisfy utilities’ appetite for low-priced pounds to meet near- to mid-term requirements. As a result, strategic inventories have grown across the industry and the need to sign significant long-term contracts has been deferred.

These industry dynamics make it difficult to predict the timing of a market recovery. However, given that Ux Consulting Company, LLC (UxC) reports that over the last four years only 245 million pounds have been locked-up in the long-term market, while over 635 million pounds have been consumed in reactors, we remain confident that utilities have a growing gap to fill. As annual supply adjusts and utilities’ uncovered requirements grow, we believe the pounds available in the spot market won’t be enough to satisfy the demand.

OPPORTUNITIES FOR THOSE WHO CAN WAIT

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 9

Like other commodities, the uranium industry is cyclical and the low level of contracting at low prices that we’re seeing today is not new. When prices are low, there is no urgency to contract. The heavy contracting that took place during the previous price run, which drove investment in higher-cost sources of production, contributes to the perception that uranium is abundant and always will be. History demonstrates that the opposite tends to occur when prices rise. After years of low investment in supply, as has been the case so far this decade, security of supply tends to overtake price concerns at some point, and utilities re-enter the long-term market to ensure they have the reliable supply of uranium they need to run their reactors.

The backlog of future contracting needs created by the low-price environment presents a substantial opportunity for suppliers like us that can weather the low-price part of the cycle. As a low-cost producer, we plan our business with these price cycles in mind.

In our industry, customers don’t come to the market right before they need to load uranium into their reactors. To operate a reactor that could run for more than 60 years, natural uranium and the downstream services have to be purchased years in advance, allowing time for a number of processing steps before it arrives at the power plant as a finished fuel bundle. At present, we believe there is a significant amount of uranium that needs to be contracted to keep reactors running into the next decade.

Estimates by industry consultants show cumulative uncovered requirements to be about 800 million pounds over the next nine years. While uncovered requirements do not ramp up significantly in the near-term, the longer the delay in the recovery of the long-term market, the less certainty there is around the availability of future supply to fill growing demand. Ultimately, we expect the current price-sensitive sentiment to give way to increasing concerns about the security of future supply.

SUPPLY IS NOT GUARANTEED

Economic difficulties are beginning to take a toll on the supply side. Producers who have been protected from the low market prices under long-term contracts, are beginning to emerge from that protection. As a result, it is not just future supply that is at risk – we are seeing evidence that even existing supply is at risk:

• |  | most recently, Kazatomprom announced its intention to reduce 2017 output from Kazakhstan by 10%, citing market challenges due to the current oversupply situation

• |  | Paladin has announced reduced production from their 75% owned Langer Heinrich mine and modification of the mine plan to reduce costs

• |  | in the conversion space, Honeywell is making permanent adjustments to its operation and lowering nameplate capacity of their facility from 15 million kgU to 7 million kgU as UF6

• |  | some enrichers are retiring centrifuge capacity, reducing the excess capacity in the enrichment space that is contributing to broader oversupply via underfeeding and tails re-enrichment

• |  | we have suspended and curtailed three operations in addition to taking cost-cutting measures that carry additional supply risk

Coupled with looming uncovered requirements, we expect the risks to future and existing supply could decrease the availability of spot material and increase the pressure for a return to long-term contracting.

10 |  | CAMECO CORPORATION |  |

DEMAND SIDE CHALLENGES

There was mixed news for the broader nuclear industry in 2016. On a regional demand basis, there were significant positive and negative developments:

• |  | China struggled with a lower economic growth forecast and excess capacity in the energy sector, although the country remains committed to a fast-paced and growing nuclear power program

• |  | in Japan, a total of 10 reactors now meet the new regulatory standards; however, the pace of restarts continues to be slow

• |  | India made strides in agreements with western nuclear vendors, including engineering and design work, and finalizing contractual arrangements, but the industry continues to face delays in achieving significant progress in nuclear power development

• |  | Russia saw domestic challenges due to weaker demand for electricity, but continues to pursue an aggressive reactor export strategy

• |  | US operators announced additional early reactor closures, but policy developments in some states targeted support for keeping at-risk reactors profitable

| • |  | A number of additional reactors remain under threat of early closure subject to political and energy policy support

| • |  | It remains to be seen what impact the new US administration will have on the success of their reactor program

• |  | in the United Arab Emirates, construction of four units is proceeding smoothly, with the startup of the first unit expected in 2017, but continued growth remains uncertain

• |  | the United Kingdom approved construction of Hinkley Point C, but the rest of Europe is expecting little to no growth in nuclear power in the next 10 years

• |  | advances were also made in the potential growth of some other existing nuclear programs (South Korea, South Africa) and new nuclear programs (Bangladesh), while steps in the opposite direction occurred in other jurisdictions (Vietnam and Taiwan)

• |  | in Canada, the Province of Ontario has shown a strong commitment to nuclear power for nearly 50 years, but continued support is subject to a successful refurbishment program

• |  | several units in France’s nuclear fleet were taken offline due to regulatory reviews linked to technical issues, though some have been cleared for restart. France is also showing signs of reversing a previously announced intention to reduce reliance on nuclear power.

While 2016 offered some welcome progress in bringing supply and demand closer to equilibrium, uncertainty persists.

WHAT HAS TO CHANGE?

Ultimately, the industry needs to fill the demand gap left by forced and premature shut-downs since March of 2011 by continuing to safely bring reactors online. This means Japanese restarts, successful commissioning of new reactors under construction, and continued development of new construction plans. And we’re seeing positive progress on all fronts:

• |  | Japanese utilities have now successfully navigated through the new, rigorous safety inspection process

• |  | 58 reactors are currently under construction around the world, the majority of which are expected to come online in the next three years

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 11

• |  | the growth in nuclear power generation is real, with 10 new reactors connected to the grid in 2016

Global population is on the rise, and with the world’s need for safe, clean, reliable baseload energy, nuclear remains an important part of the mix. We remain confident in the future of the nuclear industry, while at the same time recognizing that uncertainty persists.

With demand coming on in the form of restarts and new reactors, and supply falling on curtailments and lack of investment, we’re continuing to expect a market shift. Until that time, we will continue to take the actions we believe are necessary to position the company for long-term success. Therefore, we will undertake contracting activity which aligns with the uncertain timing of a market recovery intended to ensure we have adequate protection under our contract portfolio, while maintaining exposure to the rewards that come from having uncommitted, low-cost supply to deliver into a strengthening market.

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Our strategy

Tier-one focus

Our strategy is set within the context of a challenging market environment, which we expect to give way to strong long-term fundamentals driven by increasing population and electricity demand.

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

URANIUM

Uranium production is central to our strategy, as it is the biggest value driver of the nuclear fuel cycle and our business. We plan to focus on our tier-one assets and manage our supply according to market conditions in order to return the best value possible. During a prolonged period of uncertainty, our tier-one strategy helps to mitigate risk. As conditions improve, we expect to meet rising demand with production from our best margin operations.

In light of today’s oversupplied market and the lingering uncertainty as to how long the weak market conditions will persist, we are focussing our resources on our lowest cost assets, on maintaining a strong balance sheet, and on efficiently managing the company in a low price environment. Consistent with this strategy, in 2016, we suspended production at our Rabbit Lake operation in northern Saskatchewan, we curtailed production at Cameco Resources’ US operations by deferring wellfield development, and we reduced the workforce in our corporate office. In addition, actions we have planned for 2017, including a 10% reduction of the workforce at our McArthur River, Key Lake and Cigar Lake operations, changes to work rotation schedules, and changes to the commuter flight services at our sites, are all expected to further reduce costs and improve efficiency at our mining operations. See Uranium – production overview on page 55 for additional details

FUEL SERVICES

Our fuel services division is a source of profit and supports our uranium segment while allowing us to vertically integrate across the fuel cycle. Our focus is on maintaining and optimizing profitability.

ENRICHMENT

We continue to explore opportunities in the second largest value driver of the fuel cycle. Having operational control of both uranium production and enrichment facilities would offer operational synergies that could enhance profit margins.

NUKEM

NUKEM’s activities provide a source of profit and give us insight into market dynamics.

Capital allocation – focus on value

Delivering returns to our long-term shareholders is a top priority. We continually evaluate our investment options to ensure we allocate our capital in a way that we believe will:

• |  | create the greatest long-term value for our shareholders

• |  | allow us to maintain our investment grade rating

• |  | ensure we execute on our dividend

To deliver value, free cash flow must be productively reinvested in the business or returned to shareholders, which requires good execution and disciplined allocation. We have a multidisciplinary capital allocation team that evaluates all possible uses of investable capital.

We start by determining how much cash we have to invest (investable capital), which is based on our expected cash flow from operations minus expenses we consider to be a higher priority, such as dividends and financing costs, and could include others. This investable capital can be reinvested in the company or returned to shareholders.

Amid the uncertain times we are facing today, the objective of our strategy is to maximize cash flow, while maintaining our investment grade rating through close management of our balance sheet metrics, allowing us to self-manage risks. Risks like:

• |  | a market that remains low for longer

• |  | litigation risk related to the CRA and TEPCO disputes

• |  | refinancing risk

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 13

With the metrics that inform that rating in mind, we have taken steps to improve margin and cash flow by focusing on our tier-one assets, and reduce operating, capital, and general and administrative spend in this time of low uranium prices.

REINVESTMENT

Before investable capital is reinvested in sustaining, capacity replacement, or growth, all opportunities are ranked and only those that meet the required risk-adjusted return criteria are considered for investment. We also must identify, at the corporate level, the expected impact on cash flow, earnings, and the balance sheet. All project risks must be identified, including the risks of not investing. Allocation of capital only occurs once an investment has cleared these hurdles.

This may result in some opportunities being held back in favour of higher return investments, and should allow us to generate the best return on investment decisions when faced with multiple prospects, while also controlling our costs. If there are not enough good growth prospects internally or externally, this may result in residual investable capital, which we would then consider returning directly to shareholders.

RETURN

If we determine the best use of cash is to return it to shareholders, we can do that through a share repurchase or dividend—either a one-time special dividend or a dividend growth policy. When deciding between these options, we consider a number of factors, including generation of excess cash, growth prospects for the company, growth prospects for the industry, and the nature of the excess cash.

Share buyback: If we were generating excess cash while there were little or no growth prospects for the company or the industry, then a share buyback might make sense. However, our current view is that the long-term fundamentals for Cameco and the industry remain strong.

Dividend: We view our dividend as a priority. It is evaluated by our board of directors on a quarterly basis with careful consideration of long-term sustainability. A re-assessment of our current dividend would require a significant fact change at the industry or company level.

Marketing strategy – balanced contract portfolio

As with our corporate strategy and approach to capital allocation, the purpose of our marketing strategy is to deliver value. Our approach is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that optimizes our realized price.

Uranium is not traded in meaningful quantities on a commodity exchange. Utilities have historically bought the majority of their uranium and fuel services products under long-term contracts with suppliers, and have met the rest of their needs on the spot market. We sell uranium and fuel services directly to nuclear utilities around the world as uranium concentrates, UO2 and UF6, conversion services, or fuel fabrication. We have a solid portfolio of long-term sales contracts that reflect the long-term, trusting relationships we have with our customers.

In addition, we are active in the spot market, buying and selling uranium when it is beneficial for us. Our NUKEM business segment enhances our ability to participate, as they are one of the world’s leading traders of uranium and uranium-related products. We undertake activity in the spot market prudently, looking at the spot price and other business factors to decide whether it is appropriate to purchase or sell into the spot market. Not only is this activity a source of profit, it gives us insight into underlying market fundamentals.

LONG-TERM CONTRACTING

We deliver large volumes of uranium every year, therefore our net earnings and operating cash flows are affected by changes in the uranium price. Market prices are influenced by the fundamentals of supply and demand, geopolitical events, disruptions in planned supply and demand, and other market factors.

The objective of our contracting strategy is to:

• |  | maximize realized price while reducing volatility of our future earnings and cash flow

• |  | focus on meeting the nuclear industry’s growing uncovered requirements with our future uncommitted supply while ensuring adequate regional diversity

• |  | establish and grow market share with strategic customers

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We target a ratio of 40% fixed-pricing and 60% market-related pricing in our portfolio of long-term contracts, including mechanisms to protect us when the market price is declining and allow us to benefit when market prices go up. This is a balanced and flexible approach that allows us to adapt to market conditions and put a floor on our average realized price, and deliver the best value to shareholders over the long term.

This strategy has allowed us to realize prices higher than the market prices during periods of weak uranium demand, and we expect it will enable us to realize increases linked to higher market prices in the future.

Fixed-price contracts: are typically based on the industry long-term price indicator at the time the contract is accepted and escalated over the term of the contract.

Market-related contracts: are different from fixed-price contracts in that they may be based on either the spot price or the long-term price, and that price is as quoted at the time of delivery rather than at the time the contract is accepted. These contracts sometimes provide for discounts, and often include floor prices and/or ceiling prices, all of which are escalated over the term of the contract.

Fuel services contracts: the majority of our fuel services contracts are at a fixed price per kgU, escalated over the term of the contract, and reflect the market at the time the contract is accepted.

OPTIMIZING THE CONTRACT PORTFOLIO

In today’s weak market environment, we have been working with certain customers to optimize the value of our existing contract portfolio. In cases where a customer is seeking relief due to a challenging policy, operating, or economic environment, we evaluate their specific circumstances and assess their long-term sustainability. Where we deem the customer’s long-term demand to be at risk, we may consider options that allow us to benefit from converting that uncertain future value into certain present value. In contrast, where the customer is considered to have a more certain and predictable future, we may offer relief, for example by blending in more market-related volumes in the near term, but only where the customer is willing to extend the terms and conditions of that contract out into the future, and only where it is beneficial to us.

CUSTOMER’S FUTURE OPERATING ENVIRONMENT
UNCERTAIN |  |  |  | OPTIMISTIC
Changing |  | Policy |  | Clear pathways
Challenges |  | Regulatory |  | Established
Unregulated |  | Economic |  | Benefits recognized
Future uncertainty for present certain value |  | Resulting trade-off considerations |  | Relief where it is beneficial for us

CONTRACT PORTFOLIO STATUS

Currently, our production is heavily committed under long-term uranium contracts through 2019, so we are being selective when considering new commitments and working to achieve our contracting objectives. We have commitments to sell approximately 150 million pounds of U3O8 with 40 customers worldwide in our uranium segment, and over 50 million kilograms as UF6 conversion with 31 customers worldwide in our fuel services segment.

Customers – U3O8:

Five largest customers account for 52% of commitments

COMMITTED U3O8 SALES BY REGION

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 15

Customers – UF6 conversion:

Five largest customers account for 56% of commitments

COMMITTED UF6 SALES BY REGION

MANAGING OUR CONTRACT COMMITMENTS

To meet our delivery commitments, we use our uranium supply, which includes uranium obtained from:

• |  | our existing production

• |  | purchases under long-term agreements and in the spot market

• |  | our existing inventory

We allow sales volumes to vary year-to-year depending on:

• |  | the level of sales commitments in our long-term contract portfolio (the annual average sales commitments over the next five years in our uranium segment is 24 million pounds, with commitment levels through 2019 higher than in 2020 and 2021)

• |  | our production volumes

• |  | purchases under existing and/or new arrangements

• |  | discretionary use of inventories

• |  | market opportunities

Focusing on cost efficiency

PRODUCTION COSTS

In order to operate efficiently and cost-effectively, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology, and business process improvements. Like all mining companies, our uranium segment is affected by the cost of inputs such as labour and fuel.

2016 URANIUM OPERATING COSTS BY CATEGORY

Operating costs in our fuel services segment are mainly fixed. In 2016, labour accounted for about 52% of the total. The largest variable operating cost is for zirconium, followed by energy (natural gas and electricity), maintenance supplies, and anhydrous hydrogen fluoride.

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PURCHASES AND INVENTORY COSTS

Our costs are also affected by the purchases of uranium and conversion services we make under long-term contracts and on the spot market.

To meet our delivery commitments, we make use of our mined production and inventories, and we purchase material where it is beneficial to do so. The cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions. The cost of purchased material affects our cost of sales, which is determined by calculating the average of all of our sources of supply, including opening inventory, production, and purchases.

FINANCIAL IMPACT

As greater certainty returns to the uranium market, based on our view that the market will transition from being supply-driven to being demand-driven, we expect uranium prices will rise to reflect the cost of bringing on new primary production to meet growing demand.

In addition, as we execute our strategy to focus on tier-one production, we expect to see more stability in the unit cost of sales for our uranium segment.

Sustainable development: A key part of our strategy

Social responsibility and environmental protection are top priorities for us, so much so that we have built our corporate objectives around them within our four measures of success: a safe, healthy and rewarding workplace, a clean environment, supportive communities, and outstanding financial performance. For us, sustainability isn’t an add-on for our company; it’s at the core of our company culture. It helps us:

• |  | build trust, credibility and corporate reputation

• |  | gain and enhance community support for our operations and plans

• |  | attract and retain employees

• |  | manage risk

• |  | drive innovation and continual improvement to build competitive advantage

Because they are so important, we integrate sustainable development principles and practices at each level of our organization, from our overall corporate strategy to individual employee practice in day-to-day operations.

Consequently, we recognize that changes in our operations and support functions, including the suspension of production at Rabbit Lake, curtailment at Cameco Resources’ US operations, and the reduction of the workforce at our northern Saskatchewan operations and at our corporate office, all have a significant impact on the communities where we operate. While we regret the negative impact that these carefully deliberated decisions have on affected employees and other stakeholders, these actions are deemed necessary for the long-term health of the company in a uranium market that continues to be weak and oversupplied. Improving operational efficiency is part of our strategy to effectively manage costs and remain competitive through these low times, while positioning the company and our stakeholders to benefit as the market improves.

SAFE, HEALTHY, REWARDING WORKPLACE

We are committed to living a strong safety culture, while looking to continually improve. As a result of this commitment, we have a long history of strong safety performance at our operations and across the organization.

2016 Highlights:

• |  | several operations reached significant safety milestones, including the Blind River refinery and the Crow Butte operation passing 10 and 9 years respectively, without a lost time incident

• |  | continued low average dose of radiation to workers while ramping up Cigar Lake

• |  | awarded the John T Ryan National Safety award at McArthur River mine based on prior year performance for the third year in a row

• |  | recognized for several top employer awards

A CLEAN ENVIRONMENT

We are committed to being a leading environmental performer. We strive to be a leader not only by complying with legal requirements, but also by keeping risks as low as reasonably achievable, and looking for opportunities to move beyond requirements.

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We track our progress by monitoring the air, water and land near our operations, and by measuring the amount of energy we use and the amount of waste generated. We use this information to help identify opportunities to improve.

2016 Highlights:

• |  | sustained the significantly reduced uranium-to-air emissions achieved at our Port Hope conversion facility in 2014

• |  | continued to reduce low level radioactive waste stored at our Fuel Services division facilities

• |  | improved effluent performance at the McArthur River mine

• |  | successfully transitioned the Rabbit Lake operation into care and maintenance with no significant environmental incident

• |  | continued to carry out industry leading research and innovation in groundwater restoration at our US in situ recovery operations

SUPPORTIVE COMMUNITIES

Gaining the trust and support of our communities, indigenous people, and governments is necessary to sustain our business. We earn support and trust through excellent safety and environmental performance, by proactively engaging our stakeholders in an open and transparent way, and by making a difference in communities wherever we operate. These efforts are critical to obtaining and maintaining the necessary regulatory approvals.

2016 Highlights:

• |  | over $210 million in procurement from locally owned northern Saskatchewan companies (80% of total)

• |  | 1,088 local personnel from northern Saskatchewan (704 Cameco employees, 384 contractors)

• |  | signed a Collaboration Agreement, our third in the region, with the seven communities of the Athabasca, including three First Nations

• |  | community engagement activities at all of our operations

• |  | continued work on groundwater restoration with five universities, Los Alamos National Laboratory, and the United States Geological Survey

OUTSTANDING FINANCIAL PERFORMANCE

Long-term financial stability and profitability are essential to our sustainability as a company. We firmly believe that sound governance is the foundation for strong corporate performance.

2016 Highlights:

• |  | continue to achieve an average realized price that outperforms the market

• |  | ranked 23rd out of 231 Canadian companies by Globe and Mail in governance practices

MONITORING AND MEASUREMENT

We take the integration of sustainable development and measurement of our performance seriously. We have been producing a Sustainable Development (SD) Report since 2005, using the Global Reporting Initiative’s Sustainability Framework (GRI). It is our report card to our stakeholders. It tells them how we’re performing against globally recognized key indicators that measure our social, environmental and economic impacts in the areas that matter most to them. It provides information about our goals, where we’ve met, exceeded or struggled with them, and how we plan to do better. Our most recent SD Report was released in August, 2016 and we expect to release our next full report in 2018.

All of our operating sites are ISO 14001 compliant. In addition, we have now transitioned from individual site-based ISO 14001 certifications to a single corporate certification. We have begun to roll our operations into this single certification.

Achievements

We are a five-time Gold award winner through the Progressive Aboriginal Relations program as judged by the Canadian Council for Aboriginal Business. We are also proud to have been named one of Canada’s Top 100 Employers, Saskatchewan’s Top Employers, and Canada’s Best Diversity Employers for eight years running, and one of Canada’s Top Employers for Young People for the seventh year. We are a leading employer of indigenous peoples in Canada, and have procured nearly $3.5 billion in services from local suppliers in northern Saskatchewan since 2004.

We encourage you to review our SD report at cameco.com/about/sustainability which outlines our commitment to people and the environment in more detail.

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A STRATEGIC FOCUS ON
TIER-ONE ASSETS
Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals, while maintaining the ability to respond to market conditions as they evolve.
COMMITTED TO OUR VALUES
Our values are at the core of everything we do and define who we are as a company.
SAFETY AND ENVIRONMENT
The safety of people and protection of the environment are the foundations of everything we do, locally and globally.
PEOPLE
We value the contribution of every employee and demonstrate respect for individual dignity, creativity and cultural diversity.
INTEGRITY
We lead by example, earn trust, honour our commitments and conduct our business ethically.
EXCELLENCE
Through leadership, collaboration and innovation, we strive to achieve our full potential and inspire others to reach theirs.
MEASURING
THAT COMMITMENT
Measuring our performance is an integral part of achieving our goals and ensuring we’re living up to our values over the long term. We set corporate objectives each year and assess our performance under four measures of success:
A safe, healthy, rewarding workplace
A clean environment
Supportive communities
Outstanding financial performance
19 CAMECO CORPORATION

Measuring our results

Each year, we set corporate objectives that are aligned with our strategic plan. These objectives fall under our four measures of success, and performance against specific targets under these objectives forms the foundation for a portion of annual employee and executive compensation. See our most recent management proxy circular for more information on how executive compensation is determined.

2016 OBJECTIVES1 |  | TARGET |  | RESULTS |  |  |  |
OUTSTANDING FINANCIAL PERFORMANCE
Earnings measures |  | Achieve targeted adjusted net earnings and cash flow from operations (before working capital changes). |  | Did not achieve |  | • |  | adjusted net earnings was below the minimum target
|  |  |  | • |  | cash flow from operations was below the minimum target
Capital management measures |  | Execute capital projects within the approved scope, cost and schedule. |  | Achieved |  | • |  | cost performance was under budget (better than the target)
|  |  | • |  | project milestones were achieved largely on schedule
Cigar Lake measure |  | Average daily production rate. |  | Exceeded |  | • |  | the average daily production rate mined from Cigar Lake in 2016 was higher than the target
SAFE, HEALTHY AND REWARDING WORKPLACE
Workplace safety measures |  | Strive for no injuries at all Cameco-operated sites. Maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses. |  | Partially Achieved |  | • |  | injury rates were stable but did not meet one of the two planned reduction targets for the year
|  |  | • |  | average radiation doses remained low and stable
Rewarding workplace measures |  | Attract and retain the employees needed to support operations. |  | Partially achieved |  | • |  | diversity and inclusion strategy development milestones were achieved on schedule
|  |  | • |  | turnover rate for new hires during the first year of employment was higher than the target (higher turnover)
CLEAN ENVIRONMENT
Environmental performance measures |  | Achieve divisional environmental aspect improvement targets. |  | Achieved |  | • |  | performance was within the targeted range
|  |  | • |  | there were no significant environmental incidents in 2016
SUPPORTIVE COMMUNITIES
Stakeholder support measures |  | Implement Collaboration Agreements by supporting northern business development opportunities and build corporate reputation. |  | Exceeded |  | • |  | sourcing of northern services from Northern Saskatchewan vendors was above the target
|  |  | • |  | sourcing of capital projects construction services from Northern Saskatchewan vendors was above the target
|  |  | • |  | public support index scoring was slightly above our target

1 | Detailed results for our 2016 corporate objectives and the related targets will be provided in our 2017 management proxy circular prior to our Annual Meeting of Shareholders on May 11, 2017.

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2017 objectives

OUTSTANDING FINANCIAL PERFORMANCE

| • |  | Achieve targeted adjusted net earnings and cash flow from operations.

SAFE, HEALTHY AND REWARDING WORKPLACE

| • |  | Improve workplace safety performance at all sites.

CLEAN ENVIRONMENT

| • |  | Improve environmental performance at all sites.

SUPPORTIVE COMMUNITIES

| • |  | Build and sustain strong stakeholder support for our activities.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 21

Financial results

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

23 |  | 2016 CONSOLIDATED FINANCIAL RESULTS
34 |  | OUTLOOK FOR 2017
36 |  | LIQUIDITY AND CAPITAL RESOURCES
42 |  | 2016 FINANCIAL RESULTS BY SEGMENT
42 |  | URANIUM
44 |  | FUEL SERVICES
44 |  | NUKEM
46 |  | FOURTH QUARTER FINANCIAL RESULTS
46 |  | CONSOLIDATED RESULTS
48 |  | URANIUM
50 |  | FUEL SERVICES
50 |  | NUKEM

22 |  | CAMECO CORPORATION |  |

2016 consolidated financial results

On February 1, 2017, we announced that on January 31, 2017, TEPCO, alleging force majeure, confirmed that it would not withdraw a contract termination notice it provided to Cameco Inc. with respect to a uranium supply agreement, which affects approximately 9.3 million pounds of uranium deliveries through 2028, worth approximately $1.3 billion in revenue to Cameco, including about $126 million in 2017. We see no basis for terminating the agreement. In this MD&A, our 2017 financial outlook and other disclosures relating to our contract portfolio are presented on a basis which excludes this agreement with TEPCO, which is under dispute.

HIGHLIGHTS |  |  |  |  |  |  |  |  |  |  | CHANGE FROM |
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2016 |  |  | 2015 |  |  | 20141 |  |  | 2015 TO 2016 |
Revenue |  |  | 2,431 |  |  |  | 2,754 |  |  |  | 2,398 |  |  |  | (12 | )%
Gross profit |  |  | 463 |  |  |  | 697 |  |  |  | 638 |  |  |  | (34 | )%
Net earnings (loss) attributable to equity holders |  |  | (62 | ) |  |  | 65 |  |  |  | 185 |  |  |  | (195 | )%
$ per common share (basic) |  |  | (0.16 | ) |  |  | 0.16 |  |  |  | 0.47 |  |  |  | (194 | )%
$ per common share (diluted) |  |  | (0.16 | ) |  |  | 0.16 |  |  |  | 0.47 |  |  |  | (194 | )%
Adjusted net earnings (non-IFRS, see page 24) |  |  | 143 |  |  |  | 344 |  |  |  | 412 |  |  |  | (58 | )%
$ per common share (adjusted and diluted) |  |  | 0.36 |  |  |  | 0.87 |  |  |  | 1.04 |  |  |  | (59 | )%
Cash provided by operations (after working capital changes) |  |  | 312 |  |  |  | 450 |  |  |  | 480 |  |  |  | (31 | )%

1 | 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.

Net earnings

Our net loss attributable to equity holders (net loss) in 2016 was $62 million ($0.16 per share diluted) compared to earnings of $65 million ($0.16 per share diluted) in 2015, mainly due to:

• |  | lower gross profit from our uranium and NUKEM segments

• |  | higher administration costs

• |  | higher impairment charges ($362 million in 2016; $215 million in 2015)

• |  | higher loss on disposal of assets

• |  | higher foreign exchange losses compared to gains in 2015

• |  | lower tax recovery. See Income taxes on page 28 for details.

partially offset by:

• |  | higher gross profit from our fuel services segment

• |  | gain from remeasurement of Rabbit Lake reclamation obligation

• |  | mark-to-market gains on foreign exchange derivatives compared to losses in 2015. See Foreign exchange on pages 32 and 33 for details.

• |  | gain from termination of long-term contracts

THREE-YEAR TREND

Our net earnings normally trend with revenue, but, in recent years, have been significantly influenced by unusual items.

In 2015, our net earnings were $120 million lower than in 2014 primarily due to:

• |  | higher administration costs

• |  | higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar. See Foreign exchange on pages 32 and 33 for details.

• |  | lower income tax recovery

partially offset by:

• |  | higher earnings from all segments

• |  | a decrease in impairment charges ($215 million in 2015; $327 million in 2014)

• |  | a reduction the provision related to our CRA litigation

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In addition, in 2014 there were a number of one-time items that contributed to the higher net earnings in 2014 compared to 2015, including:

• |  | a $127 million gain on the sale of our interest in BPLP in 2014

• |  | a favourable settlement of $66 million in 2014 in a dispute regarding a long-term supply contract with a utility customer

partially offset by:

• |  | payment of an early termination fee of $18 million incurred as a result of our toll conversion agreement with Springfields Fuels Limited (SFL), and settlement costs of $12 million with respect to early termination of our Series C debentures

• |  | the write-off of $41 million of assets under construction in 2014 as a result of changes made to the scope of a number of projects

Impairment charges

Production was suspended at our Rabbit Lake operation in the second quarter and as a result, we recognized an impairment charge for the full carrying value of $124 million during the second quarter.

During the fourth quarter of 2016, we recorded a $238 million write-down of the full carrying value of our interest in Kintyre, our uranium exploration project in Australia. Due to the weakening of the uranium market since the asset was purchased in 2008, and the budget decision not to allocate any further spend to the project, we concluded it was appropriate to recognize a further impairment charge for this asset. See note 8 to the financial statements.

Non-IFRS measures

ADJUSTED NET EARNINGS

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 is adjusted for impairment charges, the write-off of assets, NUKEM purchase price inventory recovery, Rabbit Lake reclamation provision adjustment, gain on interest in BPLP (after tax), 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.

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2016, 2015 and 2014.

($ MILLIONS) |  | 2016 |  |  | 2015 |  |  | 2014 |
Net earnings (loss) attributable to equity holders |  |  | (62 | ) |  |  | 65 |  |  |  | 185 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | (130 | ) |  |  | 166 |  |  |  | 47 |
NUKEM purchase price inventory recovery |  |  | (6 | ) |  |  | (3 | ) |  |  | (5 | )
Impairment charges |  |  | 362 |  |  |  | 215 |  |  |  | 327 |
Write-off of assets |  |  | — |  |  |  | — |  |  |  | 41 |
Rabbit Lake reclamation provision adjustment |  |  | (34 | ) |  |  | — |  |  |  | — |
Income taxes on adjustments |  |  | 13 |  |  |  | (99 | ) |  |  | (56 | )
Gain on interest in BPLP (after tax) |  |  | — |  |  |  | — |  |  |  | (127 | )
Adjusted net earnings |  |  | 143 |  |  |  | 344 |  |  |  | 412 |

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The following table shows what contributed to the change in adjusted net earnings for 2016.

($ MILLIONS) |  |  |  |  |
Adjusted net earnings – 2015 |  |  | 344 |
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 |  |  | (16 | )
|  | Lower realized prices ($US) |  |  | (129 | )
|  | Foreign exchange impact on realized prices |  |  | 30 |
|  | Higher costs |  |  | (49 | )
|  | change – uranium |  |  | (164 | )
Fuel services |  | Lower sales volume |  |  | (4 | )
|  | Higher realized prices ($Cdn) |  |  | 25 |
|  | Higher costs |  |  | (19 | )
|  | change – fuel services |  |  | 2 |
NUKEM |  | Gross profit |  |  | (71 | )
|  | change – NUKEM |  |  | (71 | )
Other changes |  |  |  |
Higher administration expenditures |  |  | (20 | )
Higher exploration expenditures |  |  | (2 | )
Higher loss on disposal of assets |  |  | (21 | )
Lower loss on derivatives |  |  | 19 |
Higher foreign exchange losses |  |  | (65 | )
Gain on customer contract settlements |  |  | 59 |
Higher income tax recovery |  |  | 63 |
Other |  |  | (1 | )
Adjusted net earnings – 2016 |  |  | 143 |

THREE-YEAR TREND

Our adjusted net earnings decreased from 2014 to 2015, and decreased again from 2015 to 2016.

The 17% decrease from 2014 to 2015 resulted from:

• |  | greater losses on foreign exchange derivatives due to the weakening of the Canadian dollar, see Foreign exchange on page 32 for more information

• |  | lower tax recoveries, primarily due to the write-off of our deferred tax asset in the US. See Income taxes on page 28 for details.

partially offset by:

• |  | higher earnings in our uranium and fuel services segments mainly due to a higher average realized price

• |  | higher earnings from our NUKEM segment mainly due to higher sales volumes and a higher average realized price

• |  | a reduction of the provision related to our CRA litigation, see Income taxes on page 28 for details

In addition, in 2014 there was a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in 2014 compared to 2015. The impact of the settlement was partially offset by an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL and settlement costs of $12 million with respect to the early redemption of our Series C debentures in 2014.

The 58% decrease from 2015 to 2016 resulted from:

• |  | lower gross profit from our uranium and NUKEM segments

• |  | higher administration costs

• |  | higher loss on disposal of assets

• |  | higher foreign exchange losses compared to gains in 2015

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 25

partially offset by:

• |  | higher gross profit from our fuel services segment

• |  | lower losses on foreign exchange derivatives. See Foreign exchange on page 32 for details.

• |  | gain from termination of long-term contracts

• |  | higher tax recovery. See Income taxes on page 28 for details.

Average realized prices

|  |  |  |  |  |  |  |  |  |  |  |  | CHANGE FROM |
|  |  |  | 2016 |  |  | 2015 |  |  | 2014 |  |  | 2015 TO 2016 |
Uranium1 |  | $US/lb |  |  | 41.12 |  |  |  | 45.19 |  |  |  | 47.53 |  |  |  | (9 | )%
|  | $Cdn/lb |  |  | 54.46 |  |  |  | 57.58 |  |  |  | 52.37 |  |  |  | (5 | )%
Fuel services |  | $Cdn/kgU |  |  | 25.37 |  |  |  | 23.37 |  |  |  | 19.70 |  |  |  | 9 | %
NUKEM |  | $Cdn/lb |  |  | 47.90 |  |  |  | 48.82 |  |  |  | 44.90 |  |  |  | (2 | )%

1 | Average realized foreign exchange rate ($US/$Cdn): 2016 – 1.32, 2015 – 1.27 and 2014 – 1.10.

Revenue

The following table shows what contributed to the change in revenue for 2016.

($ MILLIONS) |  |  |
Revenue – 2015 |  |  | 2,754 |
Uranium |  |  |  |
Lower sales volume |  |  | (50 | )
Lower realized prices ($Cdn) |  |  | (98 | )
Change in intersegment sales |  |  | 1 |
Fuel services |  |  |  |
Lower sales volume |  |  | (23 | )
Higher realized prices ($Cdn) |  |  | 25 |
Change in intersegment sales |  |  | (1 | )
NUKEM |  |  |  |
Change in revenue |  |  | (162 | )
Change in intersegment sales |  |  | 23 |
Other |  |  | (38 | )
Revenue – 2016 |  |  | 2,431 |

See 2016 Financial results by segment on page 42 for more detailed discussion.

THREE-YEAR TREND

In 2015, revenue increased by 15% compared to 2014 due to significant weakening of the Canadian dollar during the year, which resulted in record annual consolidated revenue and record annual revenue for our uranium segment. The realized foreign exchange rate was 1.27 compared to 1.10 in 2014. In addition, we had higher revenues in our NUKEM segment as a result of higher sales volumes, which were driven by increased market activity.

In 2016, revenue decreased by 12% compared to 2015 due to lower sales revenues in all of our operating segments as a result of reduced sales volumes in response to market conditions. In addition, we had lower revenues in our uranium and NUKEM segments as a result of the lower US dollar average realized price which was due to lower prices on market-related contracts. This was partially offset by further weakening of the Canadian dollar exchange rate realized on sales during 2016. The realized foreign exchange rate was 1.32 compared to 1.27 in 2015.

Revenue Outlook for 2017

We expect consolidated revenue to decrease in 2017 (outlook of $1,950 million to $2,080 million), based on currently committed sales volumes, due to a decrease in average realized prices in our uranium segment as a result of lower prices under both fixed and market related contracts, TEPCO contract dispute, and an expected decrease in NUKEM sales volumes. If we make additional sales with deliveries in 2017, we would expect our revenue outlook to increase.

26 |  | CAMECO CORPORATION |  |

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly. We expect the quarterly distribution of uranium deliveries in 2017 to be weighted to the second half of the year as shown below. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.

Corporate expenses

ADMINISTRATION

($ MILLIONS) |  | 2016 |  |  | 2015 |  |  | CHANGE |
Direct administration |  |  | 195 |  |  |  | 173 |  |  |  | 13 | %
Stock-based compensation |  |  | 12 |  |  |  | 14 |  |  |  | (14 | )%
Total administration |  |  | 207 |  |  |  | 187 |  |  |  | 11 | %

Direct administration costs in 2016 were $22 million higher than in 2015 due mainly to:

• |  | one-time costs related to collaboration agreements

• |  | charges related to the consolidation of office space

• |  | legal costs as we prepared the CRA case for trial, which began in October, 2016

• |  | restructuring of our NUKEM segment, and

• |  | costs related to our reduction of staffing levels at our corporate office

We recorded $12 million in stock-based compensation expenses in 2016 under our stock option, restricted share unit, deferred share unit, performance share unit and phantom stock option plans, compared to $14 million in 2015. See note 23 to the financial statements.

Administration outlook for 2017

We expect administration costs (not including stock-based compensation) to be approximately 20% lower compared to 2016 (outlook between $150 million to $160 million) due to the actions that we took during 2016 to reduce costs.

EXPLORATION

Our 2016 exploration activities remained focused on Canada and Australia. Our spend increased from $40 million in 2015 to $43 million in 2016.

Exploration outlook for 2017

We expect exploration expenses to be about $30 million in 2017 due to an overall decrease in activity on our regional exploration projects.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 27

FINANCE COSTS

Finance costs were $112 million compared to $104 million in 2015. The increase from last year was mainly a result of increased letter of credit fees. See note 18 to the financial statements.

FINANCE INCOME

Finance income was $4 million compared to $5 million in 2015, reflecting lower average cash balances in 2016.

GAINS AND LOSSES ON DERIVATIVES

In 2016, we recorded $34 million in gains on our derivatives compared to losses of $281 million in 2015. The gains reflect the strengthening of the Canadian dollar compared to the US dollar from the exchange rate at the end of 2015. See Foreign exchange on page 32 and note 25 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $94 million in 2016 compared to a recovery of $143 million in 2015. The decrease in recovery was primarily due to the change in the distribution of earnings between jurisdictions compared to 2015. In addition, in 2015, the tax recovery included a $73 million write-off of our deferred tax asset in the US, partially offset by a $42 million reduction in the provision related to the CRA litigation. See note 20 to the financial statements.

In 2016, we recorded losses of $464 million in Canada compared to $960 million in 2015, while earnings in foreign jurisdictions decreased to $310 million from $880 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate.

On an adjusted earnings basis, we recognized a tax recovery of $107 million in 2016 compared to a recovery of $44 million in 2015. Our effective tax rate was a recovery of 282% in 2016, compared to a recovery of 15% in 2015. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

($ MILLIONS) |  | 2016 |  |  | 2015 |
Pre-tax adjusted earnings1 |  |  |  |  |  |  |  |
Canada |  |  | (504 | ) |  |  | (578 | )
Foreign |  |  | 542 |  |  |  | 877 |
Total pre-tax adjusted earnings |  |  | 38 |  |  |  | 299 |
Adjusted income taxes1 |  |  |  |  |  |  |  |
Canada |  |  | (128 | ) |  |  | (177 | )
Foreign |  |  | 21 |  |  |  | 133 |
Adjusted income tax recovery |  |  | (107 | ) |  |  | (44 | )
Effective tax rate (%) |  |  | (282 | )% |  |  | (15 | )%

1 | Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures. Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measures on page 24).

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with 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.

28 |  | CAMECO CORPORATION |  |

For the years 2003 to 2011, 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. There has not yet been a decision regarding a transfer pricing penalty for 2011. 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 $350 million for the 2003 – 2016 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 the end of 2015, we received notices of reassessment for our 2003 through 2010 tax returns, and, in the fourth quarter of 2016, we received a notice of reassessment for our 2011 tax year. We have recorded a cumulative tax provision of $58 million, where an argument could be made that, based on our methodology, our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 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.

For the years 2003 through 2011, CRA issued notices of reassessment for approximately $4.1 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $1.2 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 in cash. In addition, we have provided $420 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed after 2014. 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 |  |  | 51 |  |  |  | 38 |  |  |  | 31 |  |  |  | 120 |  |  |  | 32 |  |  |  | 88 |
Total |  |  | 360 |  |  |  | 178 |  |  |  | 146 |  |  |  | 684 |  |  |  | 264 |  |  |  | 420 |

Using the methodology we believe CRA will continue to apply, and including the $4.1 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $8.1 billion of additional income taxable in Canada for the years 2003 through 2016, which would result in a related tax expense of approximately $2.4 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 these years would be between $1.75 billion and $1.95 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 $875 million and $975 million), plus related interest and instalment penalties assessed, which would be material to us.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 29

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. CRA has 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. As noted above, beginning with 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 2016, 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 2016.

$ MILLIONS |  | 2003-2016 |  |  | 2017-2018 |  |  | 2019-2023 |  |  | TOTAL |
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash payments |  |  | 187 |  |  |  | 65 - 90 |  |  |  | 145 - 170 |  |  |  | 390 - 445 |
Secured by letters of credit |  |  | 319 |  |  |  | 10 - 35 |  |  |  | 150 - 175 |  |  |  | 480 - 530 |
Total paid1 |  |  | 506 |  |  |  | 75 - 125 |  |  |  | 295 - 345 |  |  |  | 875 - 975 |

1 | These amounts do not include interest and instalment penalties, which totaled approximately $178 million to December 31, 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 $684 million already paid or otherwise secured to date.

The trial related to 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 received Revenue Agents Reports (RARs) from the IRS for the 2009 though 2012 tax years, whereby the IRS has challenged the transfer pricing used under certain intercompany transactions pertaining to the above tax years for certain of our US subsidiaries. The RARs list the adjustments proposed by the IRS and calculate the tax and any penalties owing based on the proposed adjustments.

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

30 |  | CAMECO CORPORATION |  |

Overview of disputes

The table below provides an overview of some of the key points with respect to our CRA and IRS tax disputes.

|  | CRA |  | IRS
Basis for dispute |  | • |  | Corporate structure/governance |  | • |  | Income earned on sales of uranium by the US mines to CEL is inadequate
|  | • |  | Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements |  | • |  | Compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate
|  | • |  | Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2011 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax) |  | • |  | Allocates a portion of CEL’s income for the years 2009 through 2012 to the US (a portion of the same income we paid tax on in foreign jurisdictions and which the CRA is proposing to tax)
Years under consideration |  | • |  | CRA reassessed 2003 to 2011 |  | • |  | IRS has proposed adjustments for 2009 through 2012
|  | • |  | Auditing 2012 to 2014 |  | • |  | Auditing 2013 to 2015
Timing of resolution |  | • |  | The trial related to the 2003, 2005 and 2006 reassessments commenced in October 2016, with final arguments expected in the second half of 2017 |  | • • |  | Contesting proposed adjustments in an administrative appeal We cannot yet provide an estimate as to the timeline for resolution
|  | • |  | Expect Tax Court decision six to 18 months after completion of trial |  |  |  |
Required payments |  | • |  | Expect to provide security in form of letters of credit and/or make cash payments for 50% of cash taxes, interest and penalties as reassessed |  | • |  | No security or cash payments required while under administrative appeal
|  | • |  | Paid $264 million in cash to date |  |  |  |
|  | • |  | Secured $420 million using letters of credit |  |  |  |

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

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 2012 through 2016 using a similar methodology as for the years 2003 through 2011, 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 $58 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 2012 through 2016 using a different methodology than for years 2003 through 2011, 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

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 31

Tax outlook for 2017

On an adjusted net earnings basis, we expect a tax recovery of $10 to $20 million in 2017 from our uranium, fuel services and NUKEM segments.

Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. We have a global customer base and we have established a marketing and trading structure involving foreign subsidiaries, which entered into various intercompany purchase and sale arrangements, 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.

In 2016, many of the existing intercompany purchase and sale arrangements in our portfolio expired. We have started to replace these contracts and will continue to put new intercompany arrangements in place, which, as the existing arrangements did, will reflect the market at the time they are signed.

As a result, in 2018, we expect our consolidated tax rate will transition to a modest expense, and trend toward a tax expense of approximately 20% over the next five years. The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and the market conditions at the time transactions occur under both our intercompany and third-party purchase and sale arrangements.

FOREIGN EXCHANGE

The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments.

We sell the majority of our uranium and fuel services products under long-term sales contracts, which are routinely denominated in US dollars, while our production costs are largely denominated in Canadian dollars. To provide cash flow predictability we hedge a portion of our net US/Cdn exposure (e.g. total US dollar sales less US dollar expenditures and product purchases) to manage shorter term exchange rate volatility.

Our risk management policy permits us to hedge 35% to 100% of our expected net exposure over a rolling 60-month period. Our normal practice is to layer in hedge contracts over a three- to four-year period with the hedge percentage being highest in the first 12 months and decreasing hedge percentages in subsequent years. The portion of our net exposure that remains unhedged is subject to prevailing market exchange rates for the period. Therefore, our results are affected by the movements in the exchange rate on our hedge portfolio (explained below), and on the unhedged portion of our net exposure. A weakening Canadian dollar would have a positive effect on the unhedged exposure, and a strengthening Canadian dollar would have a negative effect. See Revenue, adjusted net earnings, and cash flow sensitivity analysis on page 35 for more information on how a change in the exchange rate will impact our revenue, cash flow, adjusted net earnings (ANE), and gains and losses on derivatives, presented on an ANE basis.

Impact of hedging on IFRS earnings

We do not use hedge accounting under IFRS and, therefore, we are required to report gains and losses on all hedging activity, both for contracts that close in the period and those that remain outstanding at the end of the period. For the contracts that remain outstanding, we must treat them as though they were settled at the end of the reporting period (mark-to-market).

However, we do not believe the gains and losses that we are required to report under IFRS appropriately reflect the intent our hedging activities, so we make adjustments in calculating our ANE to better reflect the benefits of our hedging program in the applicable reporting period.

Impact of hedging on ANE

We designate contracts for use in particular periods, based on our expected net exposure in that period. Hedge contracts are layered in over time based on this expected net exposure. The result is that our current hedge portfolio is made up of a number of contracts which are currently designated to net exposures we expect in 2017, 2018 and 2019 and we will recognize the gains or losses in ANE in those periods.

32 |  | CAMECO CORPORATION |  |

For the purposes of ANE, gains and losses on derivatives are reported based on the difference between the effective hedge rate of the contracts designated for use in the particular period and the exchange rate at the time of settlement. This results in an adjustment to current period IFRS earnings to effectively remove reported gains or losses on derivatives that arise from contracts put in place for use in future periods. The effective hedge rate will lag the market in periods of rapid currency movement. See Non-IFRS measures on page 24.

The table below provides a summary of our hedge portfolio at December 31, 2016. You can use this information to estimate the expected gains or losses on derivatives for 2017 on an ANE basis. However, if we add contracts to the portfolio that are designated for use in 2017 or if there are changes in the US/Cdn exchange rates in the year, those expected gains or losses could change.

HEDGE PORTFOLIO SUMMARY

DECEMBER 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  | AFTER |  |  |  |
($ MILLIONS) |  |  |  | 2017 |  |  | 2018 |  |  | 2019 |  |  | 2019 |  |  | TOTAL |
US dollar forward contracts |  | ($ millions) |  |  | 403 |  |  |  | 290 |  |  |  | 50 |  |  |  | — |  |  |  | 743 |
Average contract rate 1 |  | (US/Cdn dollar) |  |  | 1.31 |  |  |  | 1.31 |  |  |  | 1.31 |  |  |  | — |  |  |  | 1.31 |
US dollar option contracts |  | ($ millions) |  |  | 50 |  |  |  | 20 |  |  |  | 40 |  |  |  | — |  |  |  | 110 |
Average contract rate range1 |  | (US/Cdn dollar) |  |  | 1.30 to 1.35 |  |  |  | 1.29 to 1.34 |  |  |  | 1.28 to 1.35 |  |  |  | — |  |  |  | 1.29 to 1.35 |
Total US dollar hedge contracts |  | ($ millions) |  |  | 453 |  |  |  | 310 |  |  |  | 90 |  |  |  | — |  |  |  | 853 |
Effective Hedge Rate range2 |  | (US/Cdn dollar) |  |  | 1.19 to 1.20 |  |  |  | 1.20 to 1.21 |  |  |  | 1.20 to 1.21 |  |  |  | — |  |  |  | 1.20 to 1.21 |
Hedge ratio3 |  |  |  |  | 50 | % |  |  | 32 | % |  |  | 11 | % |  |  | 0 | % |  |  | 21 | %

1 | The average contract rate is the average of the rates stipulated in the outstanding contracts.

2 | The effective hedge rate is the exchange rate on the original hedge contract at the time it was established and designated for use. Therefore the effective hedge rate range shown reflects an average of contract exchange rates at the time of designation.

3 | Hedge ratio is calculated by dividing the amount (in foreign currency) of outstanding derivative contracts by estimated future net exposures.

At December 31, 2016:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.34 (Cdn), down from $1.00 (US) for $1.38 (Cdn) at December 31, 2015. The exchange rate averaged $1.00 (US) for $1.32 (Cdn) over the year.

• |  | The mark-to-market loss on all foreign exchange contracts was $25 million compared to a $167 million loss at December 31, 2015.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2016, all of our hedging counterparties had a Standard & Poor’s (S&P) credit rating of A or better.

For information on the impact of foreign exchange on our intercompany balances, see note 25 to the financial statements.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 33

Outlook for 2017

Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.

Our outlook for 2017 reflects the expenditures necessary to help us achieve our strategy and is based on the assumptions found below the table, including a given uranium spot price, uranium term price, and foreign exchange rate. For more information on how changes in the exchange rate or uranium prices can impact our outlook see Revenue, adjusted net earnings, and cash flow sensitivity analysis on page 35, and Foreign exchange on page 32. Our 2017 financial outlook, and other disclosures relating to our contract portfolio, have been presented on a basis that excludes our contract with TEPCO, which is under dispute. 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 42 for details.

2017 FINANCIAL OUTLOOK

|  | CONSOLIDATED |  |  | URANIUM |  |  | FUEL SERVICES |  |  | NUKEM |
EXPECTED CONTRIBUTION TO GROSS PROFIT |  |  | 100 | % |  |  | 84 | % |  |  | 15 | % |  |  | 1 | %
Production |  |  | — |  |  |  | 25.2 million lbs |  |  |  | 8 to 9 million kgU |  |  |  | — |
Sales volume1 |  |  | — |  |  |  | 30 to 32 million lbs | 2 |  |  | 11 to 12 million kgU |  |  |  | 5 to 6 million lbs U3O8 |
Revenue ($ million)1 |  |  | 1,950 to 2,080 |  |  |  | 1,470 to 1,570 | 3 |  |  | 300 to 330 |  |  |  | — |
Average realized price3 |  |  | — |  |  | $ | 49.00/lb | 2 |  |  | — |  |  |  | — |
Average unit cost of sales (including D&A) |  |  | — |  |  | $ | 36.00-38.00/lb | 4 |  | $ | 21.60-22.60/kgU |  |  |  | — |
Gross profit |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3% to 4 | %
Direct administration costs5 |  | $ | 150-160 million |  |  |  | — |  |  |  | — |  |  |  | — |
Exploration costs |  |  | — |  |  | $ | 30 million |  |  |  | — |  |  |  | — |
Expected loss on derivatives - ANE basis3 |  | $ | 45-50 million |  |  |  | — |  |  |  | — |  |  |  | — |
Tax recovery - ANE basis6 |  | $ | 10-20 million |  |  |  | — |  |  |  | — |  |  |  | — |
Capital expenditures |  | $ | 190 million |  |  |  | — |  |  |  | — |  |  |  | — |

1 | Our 2017 outlook for sales volume and revenue does not include sales between our uranium, fuel services and NUKEM segments.

2 | Based on the volumes we currently have commitments to deliver under contract in 2017.

3 | Based on a uranium spot price of $26.00 (US) per pound (the Ux spot price as of February 6, 2017), a long-term price indicator of $30.00 (US) per pound (the Ux long-term indicator on January 30, 2017) and an exchange rate of $1.00 (US) for $1.30 (Cdn).

4 | Based on the expected unit cost of sales for produced material and committed long-term purchases. If we make discretionary purchases in 2017, then we expect the overall unit cost of sales may be affected.

5 | Direct administration costs do not include stock-based compensation expenses. See page 27 for more information.

6 | Our outlook for the tax recovery is based on adjusted net earnings and the other assumptions listed in the table. If other assumptions change then the expected recovery may be affected.

34 |  | CAMECO CORPORATION |  |

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

|  |  |  | IMPACT ON: |
FOR 2017 ($ MILLIONS) |  | CHANGE |  | REVENUE |  |  | ANE |  |  | CASH FLOW |
Uranium spot and term price1 |  | $5(US)/lb increase |  |  | 65 |  |  |  | 46 |  |  |  | 55 |
| $5(US)/lb decrease |  |  | (43 | ) |  |  | (29 | ) |  |  | (33 | )
Value of Canadian dollar vs US dollar |  | One cent decrease in CAD |  |  | 14 |  |  |  | 6 |  |  |  | 5 |
| One cent increase in CAD |  |  | (14 | ) |  |  | (6 | ) |  |  | (5 | )

1 | Assuming change in both Ux spot price ($26.00 (US) per pound on February 6, 2017) and the Ux long-term price indicator ($30.00 (US) per pound on January 30, 2017)

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following table is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table. It is designed to indicate how the portfolio of long-term contracts we had in place on February 1, 2017 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 February 1, 2017, and none of the assumptions we list below change.

We intend to update this table each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio. As a result, we expect the table 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 |
2017 |  |  | Provided above in financial outlook table and in revenue, adjusted net earnings, and cash flow sensitivity analysis |
2018 |  |  | 37 |  |  |  | 45 |  |  |  | 57 |  |  |  | 68 |  |  |  | 78 |  |  |  | 87 |  |  |  | 95 |
2019 |  |  | 34 |  |  |  | 44 |  |  |  | 56 |  |  |  | 66 |  |  |  | 75 |  |  |  | 83 |  |  |  | 89 |
2020 |  |  | 36 |  |  |  | 45 |  |  |  | 57 |  |  |  | 66 |  |  |  | 75 |  |  |  | 82 |  |  |  | 88 |
2021 |  |  | 33 |  |  |  | 44 |  |  |  | 58 |  |  |  | 68 |  |  |  | 77 |  |  |  | 86 |  |  |  | 94 |

The table illustrates the mix of long-term contracts in our February 1, 2017 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to February 1, 2017, and it excludes our contract under dispute with TEPCO.

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.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 35

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 24 million pounds per year, with commitment levels in 2017 through 2019 higher than in 2020 and 2021

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

• |  | excludes the contract under dispute with TEPCO

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 20% 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 ensure we have the cash and debt capacity to fund our operating activities, investments and growth.

At the end of 2016, we had cash and short-term investments of $320 million in a mix of short-term deposits, while our total debt amounted to $1.5 billion.

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 using our operating cash flow, drawing on our existing credit facilities, entering new credit facilities, 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. Due to the cyclical nature of our business, we may need to temporarily draw on our short-term liquidity during the course of the year. However, apart from these short-term fluctuations, we expect our cash balances and operating cash flows to meet our capital requirements during 2017.

We have an ongoing transfer pricing dispute with CRA. See page 28 for more information. Until this dispute is resolved, 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. We have provided an estimate of the amount and timing of the expected cash taxes and transfer pricing penalties paid, secured or owing in the table on page 30.

FINANCIAL CONDITION

|  | 2016 |  |  | 2015 |
Cash position ($ millions) |  |  | 320 |  |  |  | 459 |
(cash and cash equivalents) |  |
Cash provided by operations ($ millions) |  |  | 312 |  |  |  | 450 |
(net cash flow generated by our operating activities after changes in working capital) |  |
Cash provided by operations/net debt |  |  | 27 | % |  |  | 44 | %
(net debt is total consolidated debt, less cash position) |  |
Net debt/total capitalization |  |  | 18 | % |  |  | 16 | %
(total capitalization is net debt and equity) |  |

CREDIT RATINGS

The credit ratings assigned to our securities by external ratings agencies are important to our ability to raise capital at competitive pricing to support our business operations. Our investment grade credit ratings reflect the current financial strength of our company.

36 |  | CAMECO CORPORATION |  |

Third-party ratings for our commercial paper and senior debt as of February 8, 2017:

SECURITY |  | DBRS |  |  | S&P |
Commercial paper |  |  | R-2 (high | ) |  |  | A-1 (low | )1
Senior unsecured debentures |  |  | BBB (high | ) |  |  | BBB+ |
Rating trend / rating outlook |  |  | Stable |  |  |  | Stable | 2

1 | Canadian National Scale Rating. The Global Scale Rating is A-2.

2 | On January 19, 2017, S&P confirmed Cameco’s outlook as stable, but placed Cameco on Credit Watch Negative.

DBRS provides guidance for the outlook of the assigned rating using the rating trend. The rating trend represents their assessment of the likelihood and direction that the rating could change in the future, should present tendencies continue, or in some cases, if challenges are not overcome.

S&P uses rating outlooks to assess the potential direction of a long-term credit rating over the intermediate term. Their outlook indicates the likelihood that the rating could change in the future.

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant. A change in our credit ratings could affect our cost of funding and our access to capital through the capital markets.

Liquidity

($ MILLIONS) |  | 2016 |  |  | 2015 |
Cash and cash equivalents at beginning of year |  |  | 459 |  |  |  | 567 |
Cash from operations |  |  | 312 |  |  |  | 450 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment and acquisitions |  |  | (217 | ) |  |  | (359 | )
Other investing activities |  |  | (1 | ) |  |  | 18 |
Financing activities |  |  |  |  |  |  |  |
Interest paid |  |  | (71 | ) |  |  | (70 | )
Dividends |  |  | (158 | ) |  |  | (158 | )
Exchange rate on changes on foreign currency cash balances |  |  | (4 | ) |  |  | 11 |
Cash and cash equivalents at end of year |  |  | 320 |  |  |  | 459 |

CASH FROM OPERATIONS

Cash from operations was 31% lower than in 2015. This was primarily due to lower profits in our uranium and NUKEM segments partially offset by the settlement and rollover of contracts in our hedge portfolio which required less cash during 2016 compared to 2015. Not including working capital requirements, our operating cash flows in the year were down $140 million. See note 22 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

Capital spending

We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 37

CAMECO’S SHARE ($ MILLIONS) |  | 2016 PLAN1 |  |  | 2016 ACTUAL |  |  | 2017 PLAN |
Sustaining capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 30 |  |  |  | 18 |  |  |  | 15 |
Cigar Lake |  |  | 20 |  |  |  | 18 |  |  |  | 15 |
Rabbit Lake |  |  | 10 |  |  |  | 12 |  |  |  | — |
US ISR |  |  | 5 |  |  |  | 2 |  |  |  | 5 |
Inkai |  |  | 5 |  |  |  | 1 |  |  |  | 5 |
Fuel services |  |  | 15 |  |  |  | 12 |  |  |  | 20 |
Other |  |  | 5 |  |  |  | 5 |  |  |  | 5 |
Total sustaining capital |  |  | 90 |  |  |  | 68 |  |  |  | 65 |
Capacity replacement capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 40 |  |  |  | 39 |  |  |  | 45 |
Cigar Lake |  |  | 20 |  |  |  | 19 |  |  |  | 50 |
US ISR |  |  | 5 |  |  |  | 8 |  |  |  | — |
Inkai |  |  | 10 |  |  |  | 12 |  |  |  | 15 |
Total capacity replacement capital |  |  | 75 |  |  |  | 78 |  |  |  | 110 |
Growth capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 35 |  |  |  | 29 |  |  |  | 10 |
Cigar Lake |  |  | 30 |  |  |  | 35 |  |  |  | — |
Inkai |  |  | 10 |  |  |  | 4 |  |  |  | 5 |
Fuel services |  |  | 5 |  |  |  | 3 |  |  |  | — |
Total growth capital |  |  | 80 |  |  |  | 71 |  |  |  | 15 |
Total uranium & fuel services |  |  | 245 | 1 |  |  | 217 |  |  |  | 190 |

1 | Capital spending outlook was updated to $245 million (from $320 million) in our third quarter MD&A.

Outlook for investing activities

CAMECO’S SHARE ($ MILLIONS) |  | 2018 PLAN |  |  | 2019 PLAN |
Total uranium & fuel services |  |  | 200-250 |  |  |  | 200-250 |
Sustaining capital |  |  | 70-90 |  |  |  | 85-105 |
Capacity replacement capital |  |  | 110-125 |  |  |  | 100-115 |
Growth capital |  |  | 20-35 |  |  |  | 15-30 |

We expect total 2017 capital expenditures for uranium and fuel services to be about 12% lower than in 2016.

Major sustaining, capacity replacement and growth expenditures in 2017 include:

• |  | McArthur River/Key Lake – the expansion of freeze capacity and mine development.

• |  | Cigar Lake – work to expand freezing capacity and underground development make up the largest portion of capital at the Cigar Lake site.

Our expectation to spend between $200 million and $250 million in 2018 remains unchanged.

This information regarding currently expected capital expenditures for future periods is forward-looking information, and is based upon the assumptions and subject to the material risks discussed on pages 2 and 3. Our actual capital expenditures for future periods may be significantly different.

FINANCING ACTIVITIES

Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance.

38 |  | CAMECO CORPORATION |  |

Long-term contractual obligations

DECEMBER 31 ($ MILLIONS) |  | 2017 |  |  | 2018 AND 2019 |  |  | 2020 AND 2021 |  |  | 2022 AND BEYOND |  |  | TOTAL |
Long-term debt |  |  | — |  |  |  | 500 |  |  |  | — |  |  |  | 1,000 |  |  |  | 1,500 |
Interest on long-term debt |  |  | 69 |  |  |  | 139 |  |  |  | 82 |  |  |  | 185 |  |  |  | 475 |
Provision for reclamation |  |  | 18 |  |  |  | 95 |  |  |  | 82 |  |  |  | 842 |  |  |  | 1,037 |
Provision for waste disposal |  |  | 2 |  |  |  | 12 |  |  |  | 1 |  |  |  | — |  |  |  | 15 |
Other liabilities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 70 |  |  |  | 70 |
Capital commitments |  |  | 51 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 51 |
Total |  |  | 140 |  |  |  | 746 |  |  |  | 165 |  |  |  | 2,097 |  |  |  | 3,148 |

We have contractual capital commitments of approximately $51 million at December 31, 2016. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfil the contracts.

We have unsecured lines of credit of about $2.8 billion, which include the following:

• |  | A $1.25 billion unsecured revolving credit facility that matures November 1, 2020. Each year on the anniversary date, and upon mutual agreement, the facility can be extended for an additional year. In addition to borrowing directly from this facility, we can use up to $100 million of it to issue letters of credit and we may use it to provide liquidity for our commercial paper program, as necessary. We may increase the revolving credit facility above $1.25 billion, by increments of no less than $50 million, up to a total of $1.75 billion. The facility ranks equally with all of our other senior debt. At December 31, 2016, there were no amounts outstanding under this facility.

• |  | At December 31, 2016, we had approximately $1.5 billion outstanding in letters of credit provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, for our obligations relating to the CRA dispute, and as overdraft protection.

In total we have $1.5 billion in senior unsecured debentures outstanding:

• |  | $500 million bearing interest at 5.67% per year, maturing on September 2, 2019

• |  | $400 million bearing interest at 3.75% per year, maturing on November 14, 2022

• |  | $500 million bearing interest at 4.19% per year, maturing on June 24, 2024

• |  | $100 million bearing interest at 5.09% per year, maturing on November 14, 2042

Debt covenants

Our revolving credit facility includes the following financial covenants:

• |  | our funded debt to tangible net worth ratio must be 1:1 or less

• |  | other customary covenants and events of default

Funded debt is total consolidated debt less non-recourse debt, $100 million in letters of credit, cash and short-term investments.

Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2016, we complied with all covenants, and we expect to continue to comply in 2017.

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 7 and 14 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 December 31, 2016, we had $4.9 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.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 39

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at the end of 2016:

• |  | purchase commitments

• |  | financial assurances

• |  | other arrangements

Purchase commitments

We make purchases under long-term contracts where it is beneficial for us to do so and in order to support our long-term contract portfolio. These commitments include a mix of fixed price and market-related contracts, and are with entities that buy and sell uranium and uranium-related products. 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. The table below is based on our purchase commitments at February 1, 2017. 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.

FEBRUARY 1, 2017 ($ MILLIONS) |  | 2017 |  |  | 2018 AND 2019 |  |  | 2020 AND 2021 |  |  | 2022 AND BEYOND |  |  | TOTAL |
Purchase commitments1 |  |  | 340 |  |  |  | 436 |  |  |  | 145 |  |  |  | 70 |  |  |  | 991 |

1 | Denominated in US dollars, converted to Canadian dollars at the rate of 1.30.

As of February 1, 2017, we had committed to $991 million (Cdn) for the following:

• |  | approximately 21 million pounds of U3O8 equivalent from 2017 to 2028

• |  | approximately 2 million kgU as UF6 in conversion services from 2017 to 2019

• |  | about 0.3 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

Standby letters of credit mainly provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities as well as for our obligations relating to the CRA dispute. We are required to provide letters of credit to various regulatory agencies until decommissioning and reclamation activities are complete. We are also providing letters of credit until the CRA dispute is resolved. Letters of credit are issued by financial institutions for a one-year term. At December 31, 2016 our financial assurances totaled $1.5 billion compared to $1.4 billion at December 31, 2015. The increase is mainly due to obligations relating to the CRA dispute.

Other arrangements

We use factoring arrangements where receivables arising from certain sales contracts are sold to a financial institution. Upon the sale, we assign the rights to the accounts receivable to the financial institution without recourse. This arrangement provides immediate access to cash and requires we collect payment from our customers and remit the payments to the financial institution. Expenses incurred under the arrangement are recognized within finance costs in the consolidated statement of earnings.

In addition, NUKEM enters into arrangements with third parties where receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. Upon the sale, NUKEM assigns the rights to the accounts receivable to the financial institution without recourse. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts; however, the customer is responsible for making payment directly to the financial institution. The discount at which the financial institution purchases the receivable is offset against the revenue NUKEM records on delivery of the product to the customer.

40 |  | CAMECO CORPORATION |  |

BALANCE SHEET

DECEMBER 31, ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | 2016 |  |  | 2015 |  |  | 2014 |  |  | CHANGE 2015 TO 2016 |
Inventory |  |  | 1,288 |  |  |  | 1,285 |  |  |  | 902 |  |  |  | — |
Total assets |  |  | 8,249 |  |  |  | 8,795 |  |  |  | 8,473 |  |  |  | (6 | )%
Long-term financial liabilities |  |  | 2,459 |  |  |  | 2,500 |  |  |  | 2,448 |  |  |  | (2 | )%
Dividends per common share |  |  | 0.40 |  |  |  | 0.40 |  |  |  | 0.40 |  |  |  | — |

Total product inventories did not change significantly from 2015. Higher levels of inventory in our uranium segment were offset by lower levels in our fuel services and NUKEM segments. In the uranium segment, the quantities sold were lower than the quantities produced and purchased for the year. In 2016, total volume of product inventories for this segment increased by 18% while the average cost of inventory decreased by 6% due to the impact of higher production rates at Cigar Lake, and curtailment of higher cost production. This was somewhat offset by material purchased during the year at rates higher than the average cost of inventory. At December 31, 2016, our average cost for uranium was $34.69 per pound, down from $36.72 per pound at December 31, 2015. As of December 31, 2016, we held an inventory of 28.5 million pounds of U3O8 equivalent in our uranium segment (excluding broken ore).

At the end of 2016, our total assets amounted to $8.2 billion, a decrease of $0.5 billion compared to 2015, primarily due to a decrease in property, plant and equipment due to asset impairments. In 2015, the total asset balance increased by $0.3 billion compared to 2014, primarily due to higher inventory and an increase in our deferred tax assets.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation, deferred sales and financial derivatives. Our balance did not change significantly in 2016 or 2015.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 41

2016 financial results by segment

Uranium

HIGHLIGHTS |  |  |  | 2016 |  |  | 2015 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  | 27.0 |  |  |  | 28.4 |  |  |  | (5 | )%
Sales volume (million lbs)1 |  |  |  |  | 31.5 |  |  |  | 32.4 |  |  |  | (3 | )%
Average spot price |  | ($US/lb) |  |  | 25.64 |  |  |  | 36.55 |  |  |  | (30 | )%
Average long-term price |  | ($US/lb) |  |  | 39.00 |  |  |  | 46.29 |  |  |  | (16 | )%
Average realized price |  | ($US/lb) |  |  | 41.12 |  |  |  | 45.19 |  |  |  | (9 | )%
|  | ($Cdn/lb) |  |  | 54.46 |  |  |  | 57.58 |  |  |  | (5 | )%
Average unit cost of sales (including D&A) |  | ($Cdn/lb) |  |  | 40.39 |  |  |  | 38.83 |  |  |  | 4 | %
Revenue ($ millions)1 |  |  |  |  | 1,718 |  |  |  | 1,866 |  |  |  | (8 | )%
Gross profit ($ millions) |  |  |  |  | 444 |  |  |  | 608 |  |  |  | (27 | )%
Gross profit (%) |  |  |  |  | 26 |  |  |  | 33 |  |  |  | (21 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in 2016, 32,000 pounds in sales and revenue of $1.0 million in 2015).

Production volumes in 2016 decreased by 5% compared to 2015. Planned lower production at McArthur River/Key Lake, Rabbit Lake and our US operations was partially offset by higher than expected production at Cigar Lake and slightly higher production at Inkai. See Uranium – production overview on page 55 for more information.

Uranium revenues this year were down 8% compared to 2015 due to a decrease of 5% in the Canadian dollar average realized price and a decrease in sales volumes of 3%. The spot price for uranium averaged $25.64 (US) per pound in 2016, a decline of 30% compared to the 2015 average price of $36.55 (US) per pound. Our Canadian dollar average realized price decreased by only 5% due to our contract portfolio and the effects of foreign exchange. The realized foreign exchange rate was $1.32 compared to $1.27 in 2015. Overall prices were lower than the prior year mainly due lower prices under market related contracts.

Total cost of sales (including D&A) increased by 1% ($1.27 billion compared to $1.26 billion in 2015) due to higher unit cost of sales offset by lower sales volumes. The higher 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 our US operations.

The net effect was a $164 million decrease in gross profit for the year.

The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures, see below). 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.

($CDN/LB) |  | 2016 |  |  | 2015 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 17.01 |  |  |  | 20.62 |  |  |  | (18 | )%
Non-cash cost |  |  | 11.81 |  |  |  | 11.51 |  |  |  | 3 | %
Total production cost |  |  | 28.82 |  |  |  | 32.13 |  |  |  | (10 | )%
Quantity produced (million lbs) |  |  | 27.0 |  |  |  | 28.4 |  |  |  | (5 | )%
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 49.33 |  |  |  | 46.02 |  |  |  | 7 | %
Quantity purchased (million lbs) |  |  | 8.4 |  |  |  | 12.5 |  |  |  | (33 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 33.69 |  |  |  | 36.38 |  |  |  | (7 | )%
Quantities produced and purchased (million lbs) |  |  | 35.4 |  |  |  | 40.9 |  |  |  | (13 | )%

The average cash cost of production was 18% lower in the year than in 2015. The change was primarily due to the rampup of lower cost production from Cigar Lake, and the impact of our second quarter actions to curtail production from Rabbit Lake and our US operations, where production costs are higher.

42 |  | CAMECO CORPORATION |  |

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the year, the average cash cost of purchased material was $49.33 (Cdn), or $36.21 (US) per pound, compared to $36.57 (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 years ended 2016 and 2015 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS) |  | 2016 |  |  | 2015 |
Cost of product sold |  |  | 993.0 |  |  |  | 989.2 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (115.3 | ) |  |  | (116.5 | )
Other selling costs |  |  | (8.9 | ) |  |  | (13.8 | )
Care and maintenance and severance costs |  |  | (69.6 | ) |  |  | — |
Change in inventories |  |  | 74.5 |  |  |  | 301.8 |
Cash operating costs (a) |  |  | 873.7 |  |  |  | 1,160.7 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 281.2 |  |  |  | 269.1 |
Change in inventories |  |  | 37.7 |  |  |  | 58.1 |
Total operating costs (b) |  |  | 1,192.6 |  |  |  | 1,487.9 |
Uranium produced & purchased (million lbs) (c) |  |  | 35.4 |  |  |  | 40.9 |
Cash costs per pound (a ÷ c) |  |  | 24.68 |  |  |  | 28.38 |
Total costs per pound (b ÷ c) |  |  | 33.69 |  |  |  | 36.38 |

URANIUM SEGMENT OUTLOOK

We expect to produce 25.2 million pounds in 2017 and have commitments under long-term contracts to purchase approximately 5.0 million pounds at an average price of $43.80/lb, based on the uranium price and foreign exchange rate assumptions used in our outlook table on page 34.

Based on the contracts we have in place, and not including sales between our segments, we expect to deliver between 30 and 32 million pounds of U3O8 in 2017. We expect the unit cost of sales to be lower than in 2016 (outlook between $36.00/lb to $38.00/lb), primarily due to decreased costs for care and maintenance, and severance. If we make additional discretionary purchases in 2017 at a cost different than our other sources of supply, then we expect the overall unit cost of sales to be affected.

We expect revenue to be lower than in 2016 as a result of lower average realized price (outlook $1,470 million to $1,570 million).

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 43

ROYALTIES

We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:

• |  | Basic royalty: calculated as 5% of gross sales of uranium, less the Saskatchewan resource credit of 0.75%.

• |  | Profit royalty: a 10% royalty is charged on profit up to and including $22.62/kg U3O8 ($10.26/lb) and a 15% royalty is charged on profit in excess of $22.62/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.

As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.

During the period from 2013 to 2015, transitional rules for the new profit royalty regime were applied whereby only 50% of capital costs were deductible. The remaining 50% was accumulated and was deductible beginning in 2016. In addition, the capital allowance related to Cigar Lake under the previous system was grandfathered and was also deductible beginning in 2016. As a result, only the first tier of the profit royalty (10%) applied in 2016 and we expect only the first tier (10%) to apply in 2017 as well. Beyond 2017, the applicable profit royalty tier(s) will depend on both profitability and the optimal use of capital cost deductions.

Fuel services

(includes results for UF6, UO2 and fuel fabrication) |  |  |  |  |  |  |  |  |  |  |  |
HIGHLIGHTS |  |  |  |  | 2016 |  |  | 2015 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  |  |  | 8.4 |  |  |  | 9.7 |  |  |  | (13 | )%
Sales volume (million kgU)1 |  |  |  |  |  |  | 12.7 |  |  |  | 13.6 |  |  |  | (7 | )%
Average realized price |  |  | ($Cdn/kgU) |  |  |  | 25.37 |  |  |  | 23.37 |  |  |  | 9 | %
Average unit cost of sales (including D&A) |  |  | ($Cdn/kgU) |  |  |  | 20.36 |  |  |  | 18.87 |  |  |  | 8 | %
Revenue ($ millions)1 |  |  |  |  |  |  | 321 |  |  |  | 319 |  |  |  | 1 | %
Gross profit ($ millions) |  |  |  |  |  |  | 63 |  |  |  | 61 |  |  |  | 3 | %
Gross profit (%) |  |  |  |  |  |  | 20 |  |  |  | 19 |  |  |  | 5 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (65,000 kgU in sales and revenue of $0.5 million in 2016, 339,000 kgU in sales and revenue of $2.9 million in 2015).

Total revenue increased by 1% due to a 9% increase in the realized price, partially offset by a 7% decrease in sales volumes.

The total cost of products and services sold (including D&A) remained relatively stable compared to 2015 at $258 million, as a 7% decrease in sales volumes was offset by an 8% increase in the average unit cost of sales (including D&A). When compared to 2015, the average unit cost of sales was 8% higher due to the mix of fuel services products sold.

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

FUEL SERVICES OUTLOOK

In 2017, we plan to produce 8 to 9 million kgU, and we expect sales volumes, not including intersegment sales, to be 11 to 12 million kgU. Overall revenue is expected to remain similar to 2016 (outlook $300 million to $330 million) with the lower sales volume offset by a higher expected average realized price. We expect the average unit cost of sales (including D&A) to increase to between $21.60/kgU and $22.60/kgU.

NUKEM

HIGHLIGHTS |  |  |  |  | 2016 |  |  | 2015 |  |  | CHANGE |
Sales volume U3O8 (million lbs)1 |  |  |  |  |  |  | 7.1 |  |  |  | 10.7 |  |  |  | (34 | )%
Average realized price2 |  |  | ($Cdn/lb) |  |  |  | 47.90 |  |  |  | 48.82 |  |  |  | (2 | )%
Cost of product sold (including D&A) |  |  |  |  |  |  | 419 |  |  |  | 512 |  |  |  | (18 | )%
Revenue ($ millions)1 |  |  |  |  |  |  | 391 |  |  |  | 554 |  |  |  | (29 | )%
Gross profit (loss) ($ millions) |  |  |  |  |  |  | (28 | ) |  |  | 42 |  |  |  | (167 | )%
Gross profit (loss) (%) |  |  |  |  |  |  | (7 | ) |  |  | 8 |  |  |  | (188 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in 2016, 0.9 million pounds in sales and revenue of $19.3 million in 2015).

2 | Includes U3O8, UF6, and SWU.

44 |  | CAMECO CORPORATION |  |

During 2016, NUKEM delivered 7.1 million pounds of uranium, a decrease of 3.6 million pounds compared to the previous year due to very light market activity with a lack of profitable opportunities. Revenues from NUKEM amounted to $391 million, 29% lower than in 2015 as a result of lower sales volumes and a decline in the average realized price. Gross loss percentage was 7% for 2016, compared to a gross profit of 8% for 2015.

The net effect was a $70 million decrease in gross profit. Included in the 2016 gross loss is an $18 million net write-down of inventory compared to a $3 million net recovery in 2015. The write-down in 2016 was a result of a decline in the spot price during the year.

NUKEM OUTLOOK

For 2017, NUKEM expects to deliver between 5 and 6 million pounds of uranium. The overall gross profit percentage is expected to be higher than 2016 at 3% to 4%.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 45

Fourth quarter financial results

Consolidated results

HIGHLIGHTS |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($ MILLIONS EXCEPT WHERE INDICATED) |  | 2016 |  |  | 2015 |  |  | CHANGE |
Revenue |  |  | 887 |  |  |  | 975 |  |  |  | (9 | )%
Gross profit |  |  | 157 |  |  |  | 282 |  |  |  | (44 | )%
Net loss attributable to equity holders |  |  | (144 | ) |  |  | (10 | ) |  |  | (1340 | )%
$ per common share (basic) |  |  | (0.36 | ) |  |  | (0.03 | ) |  |  | (1100 | )%
$ per common share (diluted) |  |  | (0.36 | ) |  |  | (0.03 | ) |  |  | (1100 | )%
Adjusted net earnings (non-IFRS, see page 24) |  |  | 90 |  |  |  | 151 |  |  |  | (40 | )%
$ per common share (adjusted and diluted) |  |  | 0.23 |  |  |  | 0.38 |  |  |  | (39 | )%
Cash provided by operations (after working capital changes) |  |  | 255 |  |  |  | 503 |  |  |  | (49 | )%

NET EARNINGS

In the fourth quarter of 2016, our net loss was $144 million ($(0.36) per share diluted), a decrease of $134 million compared to a net loss of $10 million ($(0.03) per share diluted) in 2015, mainly due to:

• |  | lower gross profit from all segments

• |  | higher impairment charges ($238 million in 2016; $210 million in 2015)

• |  | higher loss on disposal of assets

• |  | lower tax recovery. See Income taxes on page 28 for details.

partially offset by:

• |  | gain from remeasurement of Rabbit Lake reclamation obligation

• |  | lower mark to market losses on foreign exchange derivatives compared to 2015. See Foreign exchange on page 32 for details.

• |  | higher foreign exchange gains compared to gains in 2015

ADJUSTED NET EARNINGS

On an adjusted basis, our earnings this quarter were $90 million ($0.23 per share diluted) compared to $151 million ($0.38 per share diluted) (non-IFRS measure, see page 24) in 2015, mainly due to:

• |  | lower gross profit from all segments

• |  | higher loss on disposal of assets

• |  | lower tax recovery. See Income taxes on page 28 for details.

partially offset by:

• |  | higher foreign exchange gains compared to 2015.

We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 24 for more information. The following table reconciles adjusted net earnings with our net earnings.

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2016 |  |  | 2015 |
Net loss attributable to equity holders |  |  | (144 | ) |  |  | (10 | )
Adjustments |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | 23 |  |  |  | 10 |
Impairment charges |  |  | 238 |  |  |  | 210 |
Rabbit Lake reclamation provision adjustment |  |  | (28 | ) |  |  | — |
Income taxes on adjustments |  |  | 1 |  |  |  | (59 | )
Adjusted net earnings |  |  | 90 |  |  |  | 151 |

46 |  | CAMECO CORPORATION |  |

ADMINISTRATION

|  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($ MILLIONS) |  | 2016 |  |  | 2015 |  |  | CHANGE |
Direct administration |  |  | 49 |  |  |  | 51 |  |  |  | (4 | )%
Stock-based compensation |  |  | 6 |  |  |  | 4 |  |  |  | 50 | %
Total administration |  |  | 55 |  |  |  | 55 |  |  |  | — |

Direct administration costs were $49 million in the quarter, $2 million lower than the same period last year due to cost reduction actions, offset by higher legal costs related to our CRA trial, which began in October. Stock-based compensation expenses were $2 million higher than the fourth quarter of 2015. See note 23 to the financial statements.

Quarterly trends

HIGHLIGHTS |  | 2016 |  |  | 2015 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 887 |  |  |  | 670 |  |  |  | 466 |  |  |  | 408 |  |  |  | 975 |  |  |  | 649 |  |  |  | 565 |  |  |  | 566 |
Net earnings (loss) attributable to equity holders |  |  | (144 | ) |  |  | 142 |  |  |  | (137 | ) |  |  | 78 |  |  |  | (10 | ) |  |  | (4 | ) |  |  | 88 |  |  |  | (9 | )
$ per common share (basic) |  |  | (0.36 | ) |  |  | 0.36 |  |  |  | (0.35 | ) |  |  | 0.20 |  |  |  | (0.03 | ) |  |  | (0.01 | ) |  |  | 0.22 |  |  |  | (0.02 | )
$ per common share (diluted) |  |  | (0.36 | ) |  |  | 0.36 |  |  |  | (0.35 | ) |  |  | 0.20 |  |  |  | (0.03 | ) |  |  | (0.01 | ) |  |  | 0.22 |  |  |  | (0.02 | )
Adjusted net earnings (non-IFRS, see page 24) |  |  | 90 |  |  |  | 118 |  |  |  | (57 | ) |  |  | (7 | ) |  |  | 151 |  |  |  | 78 |  |  |  | 46 |  |  |  | 69 |
$ per common share (adjusted and diluted) |  |  | 0.23 |  |  |  | 0.30 |  |  |  | (0.14 | ) |  |  | (0.02 | ) |  |  | 0.38 |  |  |  | 0.20 |  |  |  | 0.12 |  |  |  | 0.18 |
Cash provided by (used in) operations (after working capital changes) |  |  | 255 |  |  |  | 385 |  |  |  | (51 | ) |  |  | (277 | ) |  |  | 503 |  |  |  | (121 | ) |  |  | (65 | ) |  |  | 134 |

Key things to note:

• |  | Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 66% of consolidated revenues in the fourth quarter of 2016 and 70% of consolidated revenues in the fourth quarter of 2015.

• |  | The timing of customer requirements, which tends to vary from quarter to quarter, drives revenue in the uranium and fuel services segments.

• |  | 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 24 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.

• |  | Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

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

HIGHLIGHTS |  | 2016 |  |  | 2015 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Net earnings (loss) attributable to equity holders |  |  | (144 | ) |  |  | 142 |  |  |  | (137 | ) |  |  | 78 |  |  |  | (10 | ) |  |  | (4 | ) |  |  | 88 |  |  |  | (9 | )
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | 23 |  |  |  | (27 | ) |  |  | (10 | ) |  |  | (116 | ) |  |  | 10 |  |  |  | 112 |  |  |  | (57 | ) |  |  | 101 |
NUKEM purchase price inventory recovery |  |  | — |  |  |  | — |  |  |  | (6 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (3 | )
Impairment charges |  |  | 238 |  |  |  | — |  |  |  | 124 |  |  |  | — |  |  |  | 210 |  |  |  | — |  |  |  | — |  |  |  | 6 |
Rabbit Lake reclamation provision adjustment |  |  | (28 | ) |  |  | (6 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Income taxes on adjustments |  |  | 1 |  |  |  | 9 |  |  |  | (28 | ) |  |  | 31 |  |  |  | (59 | ) |  |  | (30 | ) |  |  | 15 |  |  |  | (26 | )
Adjusted net earnings (losses) (non-IFRS, see page 24) |  |  | 90 |  |  |  | 118 |  |  |  | (57 | ) |  |  | (7 | ) |  |  | 151 |  |  |  | 78 |  |  |  | 46 |  |  |  | 69 |

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 47

Fourth quarter financial results by segment

Uranium

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  | 2016 |  |  | 2015 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  | 7.1 |  |  |  | 9.6 |  |  |  | (26 | )%
Sales volume (million lbs)1 |  |  |  |  | 11.7 |  |  |  | 11.2 |  |  |  | 4 | %
Average spot price |  | ($US/lb) |  |  | 19.00 |  |  |  | 35.45 |  |  |  | (46 | )%
Average long-term price |  | ($US/lb) |  |  | 32.83 |  |  |  | 44.00 |  |  |  | (25 | )%
Average realized price |  | ($US/lb) |  |  | 38.04 |  |  |  | 46.36 |  |  |  | (18 | )%
|  | ($Cdn/lb) |  |  | 50.51 |  |  |  | 61.24 |  |  |  | (18 | )%
Average unit cost of sales (including D&A) |  | ($Cdn/lb) |  |  | 38.29 |  |  |  | 38.25 |  |  |  | — |
Revenue ($ millions)1 |  |  |  |  | 589 |  |  |  | 687 |  |  |  | (14 | )%
Gross profit ($ millions) |  |  |  |  | 143 |  |  |  | 257 |  |  |  | (44 | )%
Gross profit (%) |  |  |  |  | 24 |  |  |  | 37 |  |  |  | (35 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in Q4 2016, 17,000 pounds in sales and revenue of $0.5 million in Q4 2015).

Production volumes this quarter were 26% lower compared to the fourth quarter of 2015, mainly as a result of lower production at Inkai, and planned lower production at Rabbit Lake and our US operations, partially offset by an increase in Cigar Lake production. See Uranium – production overview on page 55 for more information.

Uranium revenues were down 14% due to an 18% decrease in the average realized price partially offset by a 4% increase in sales volumes. Our US and Canadian dollar average realized price decreased due to lower average spot and long term prices, which affected our market-related contracts.

Total cost of sales (including D&A) increased by 4% ($447 million compared to $429 million in 2015). This was the result of a 4% increase in sales volumes. Average unit cost of sales remained stable, as the effects of care and maintenance were offset by lower production costs related to the curtailment of higher cost production.

The net effect was a $114 million decrease in gross profit for the quarter.

The following table 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 DECEMBER 31 |  |  |  |
($/LB) |  | 2016 |  |  | 2015 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 15.00 |  |  |  | 16.04 |  |  |  | (6 | )%
Non-cash cost |  |  | 10.74 |  |  |  | 10.96 |  |  |  | (2 | )%
Total production cost |  |  | 25.74 |  |  |  | 27.00 |  |  |  | — |
Quantity produced (million lbs) |  |  | 7.1 |  |  |  | 9.6 |  |  |  | (26 | )%
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 50.49 |  |  |  | 43.65 |  |  |  | 16 | %
Quantity purchased (million lbs) |  |  | 2.2 |  |  |  | 3.2 |  |  |  | (31 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 31.59 |  |  |  | 31.16 |  |  |  | 1 | %
Quantities produced and purchased (million lbs) |  |  | 9.3 |  |  |  | 12.8 |  |  |  | (27 | )%

The average cash cost of production was 6% lower for the quarter than in the comparable period in 2015.

48 |  | CAMECO CORPORATION |  |

Although purchased pounds are transacted in US dollars, we account for the purchases in Canadian dollars. In the fourth quarter, the average cash cost of purchased material was $50.49 (Cdn) per pound, or $37.61 (US) per pound in US dollar terms, compared to $33.79 (US) per pound in the fourth quarter of 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 fourth quarters of 2016 and 2015.

CASH AND TOTAL COST PER POUND RECONCILIATION

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2016 |  |  | 2015 |
Cost of product sold |  |  | 338.4 |  |  |  | 328.3 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (38.0 | ) |  |  | (49.5 | )
Other selling costs |  |  | (0.3 | ) |  |  | (6.7 | )
Care and maintenance and severance costs |  |  | (10.8 | ) |  |  | — |
Change in inventories |  |  | (71.7 | ) |  |  | 21.5 |
Cash operating costs (a) |  |  | 217.6 |  |  |  | 293.6 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 108.1 |  |  |  | 100.9 |
Change in inventories |  |  | (31.9 | ) |  |  | 4.3 |
Total operating costs (b) |  |  | 293.8 |  |  |  | 398.8 |
Uranium produced & purchased (million lbs) (c) |  |  | 9.3 |  |  |  | 12.8 |
Cash costs per pound (a ÷ c) |  |  | 23.40 |  |  |  | 22.94 |
Total costs per pound (b ÷ c) |  |  | 31.59 |  |  |  | 31.16 |

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 49

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  | 2016 |  |  | 2015 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  | 1.9 |  |  |  | 3.4 |  |  |  | (44 | )%
Sales volume (million kgU)1 |  |  |  |  | 4.0 |  |  |  | 4.5 |  |  |  | (11 | )%
Average realized price |  | ($Cdn/kgU) |  |  | 26.03 |  |  |  | 21.88 |  |  |  | 19 | %
Average unit cost of sales (including D&A) |  | ($Cdn/kgU) |  |  | 21.17 |  |  |  | 17.18 |  |  |  | 23 | %
Revenue ($ millions)1 |  |  |  |  | 104 |  |  |  | 99 |  |  |  | 5 | %
Gross profit ($ millions) |  |  |  |  | 19 |  |  |  | 21 |  |  |  | (10 | )%
Gross profit (%) |  |  |  |  | 18 |  |  |  | 21 |  |  |  | (14 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in Q4 2016, 339,000 kgU in sales and revenue of $2.9 million in Q4 2015).

Total revenue increased by 5% due to a 19% increase in average realized price, partially offset by an 11% decrease in sales volumes. The increase in average realized price was due to the mix of products sold.

The total cost of sales (including D&A) increased by 9% ($85 million compared to $78 million in the fourth quarter of 2015) mainly due to an increase of 23% in the average unit cost of sales, primarily as a result of the mix of products sold, partially offset by an 11% decrease in sales volumes.

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

NUKEM

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  | 2016 |  |  | 2015 |  |  | CHANGE |
Uranium sales (million lbs)1 |  |  |  |  | 3.1 |  |  |  | 3.7 |  |  |  | (16 | )%
Average realized price |  | ($Cdn/lb) |  |  | 46.63 |  |  |  | 52.22 |  |  |  | (11 | )%
Cost of product sold (including D&A)2 |  |  |  |  | 195 |  |  |  | 186 |  |  |  | 5 | %
Revenue ($ millions)1,2 |  |  |  |  | 194 |  |  |  | 192 |  |  |  | 1 | %
Gross profit (loss) ($ millions)2 |  |  |  |  | (1 | ) |  |  | 6 |  |  |  | (117 | )%
Gross profit (loss) (%)2 |  |  |  |  | (1 | ) |  |  | 3 |  |  |  | (133 | )%

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

2 | Includes U3O8, UF6, and SWU.

NUKEM delivered 3.1 million pounds of uranium, a decrease of 0.6 million pounds compared to 2015. NUKEM revenues amounted to $194 million compared to $192 million in 2015 due to sales of UF6 and SWU in the quarter, partially offset by the decrease in uranium volumes delivered and lower average realized price for uranium.

Gross profit percentage was a loss of 1% in the fourth quarter of 2016, compared to gross profit of 3% in the fourth quarter of 2015.

The net effect was a $7 million decrease in gross profit.

50 |  | CAMECO CORPORATION |  |

Our operations and projects

This section of our MD&A is an overview of each of our operations, what we accomplished this year, our plans for the future and how we manage risk.

52 |  | MANAGING THE RISKS
55 |  | URANIUM – PRODUCTION OVERVIEW
55 |  | PRODUCTION OUTLOOK
56 |  | URANIUM – OPERATING PROPERTIES
56 |  | MCARTHUR RIVER MINE / KEY LAKE MILL
60 |  | CIGAR LAKE
64 |  | INKAI
68 |  | URANIUM – CURTAILED OPERATIONS
68 |  | RABBIT LAKE
68 |  | SMITH RANCH-HIGHLAND
68 |  | CROW BUTTE
69 |  | URANIUM – PROJECTS UNDER EVALUATION
69 |  | MILLENNIUM
69 |  | YEELIRRIE
69 |  | KINTYRE
71 |  | URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
72 |  | FUEL SERVICES
72 |  | BLIND RIVER REFINERY
73 |  | PORT HOPE CONVERSION SERVICES
73 |  | CAMECO FUEL MANUFACTURING INC. (CFM)
75 |  | NUKEM GMBH

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 51

Managing the risks

The nature of our operations means we face many potential risks and hazards that could have a significant impact on our business. Our risk policy and process involves a broad, systematic approach to identifying, assessing, reporting and managing the significant risks we face in our business and operations. The policy establishes clear accountabilities for enterprise risk management. We use a common risk matrix throughout the company and consider any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan as an enterprise risk. However, there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause. We recommend you read our most recent management proxy circular for more information about our risk oversight.

Below we list the regulatory, environmental and operational risks that generally apply to all of our operations and projects under evaluation. We also talk about how we manage specific risks in each operation or project update. These risks could have a material impact on our business in the near term.

We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.

Regulatory risks

A significant part of our economic value depends on our ability to:

• |  | obtain and renew the licences and other approvals we need to operate, to increase production at our mines and to develop new mines. If we do not receive the regulatory approvals we need, or do not receive them at the right time, then we may have to delay, modify or cancel a project, which could increase our costs and delay or prevent us from generating revenue from the project. Regulatory review, including the review of environmental matters, is a long and complex process.

• |  | comply with the conditions in these licences and approvals. Our right to continue operating facilities, increase production at our mines and develop new mines depends on our compliance with these conditions.

• |  | comply with the extensive and complex laws and regulations that govern our activities. Environmental legislation imposes strict standards and controls on almost every aspect of our operations and projects, and is not only introducing new requirements, but also becoming more stringent. For example:

| • |  | we must complete the environmental assessment process before we can begin developing a new mine or make any significant change to our operations

| • |  | we may need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an extensive review of supporting technical information. The complexity of this process can be further compounded when regulatory approvals are required from multiple agencies.

| • |  | the federal government’s review of environmental and regulatory processes “to restore public trust” is now firmly underway. This includes reviews of the Canadian Environmental Assessment Act, 2012, along with the Fisheries Act and Navigation Protection Act. Changes to this legislation could impact any future planned projects.

| • |  | Environment Canada has brought forward a national recovery plan for woodland caribou that has the potential to impact economic and social development in northern Saskatchewan. Additional research work has resulted in a recent report indicating the range in which our northern Saskatchewan operations are located, hosts a secure and self-sustaining population of woodland caribou, perhaps one of the most secure boreal caribou populations in Canada. The research should lead Environment and Climate Change Canada to revise the national recovery plan to recognize the sustainability of the species in northern Saskatchewan; however, potential habitat protection measures could still have an impact on our Saskatchewan operations and projects under evaluation.

| • |  | Environment Canada has been reviewing the Metal Mining Effluent Regulations (MMER). This review could result in new limits for existing MMER substances and proposed limits for new substances that could impact our Saskatchewan operations.

| • |  | The U.S. Environmental Protection Agency (EPA) proposed adding new health and environmental protection standards that could impact Cameco Resources. Particularly concerning is the proposed requirement that groundwater must be monitored for 30 years after restoration. In early 2017, the EPA withdrew its rule, but then proposed a new rule for public comment, which is less onerous though still has a number of problematic aspects. Ultimately, the decision on moving forward with EPA’s new proposal will be decided by the new administration.

| • |  | In late 2016, EPA released a proposed rule that would impose additional financial responsibility requirements on owners and operators, along with various recordkeeping and notification requirements. If finalized as proposed, it would apply to Crow Butte and Smith Ranch-Highland, and the amount of Cameco Resources’ financial responsibility could be material.

52 |  | CAMECO CORPORATION |  |

We use significant management and financial resources to manage our regulatory risks.

Environmental risks

We have the safety, health and environmental risks associated with any mining and chemical processing company. Our uranium and fuel services segments also face unique risks associated with radiation.

Laws to protect the environment are becoming more stringent for members of the nuclear energy industry and have inter-jurisdictional aspects (both federal and provincial/state regimes are applicable). Once we have permanently stopped mining and processing activities at an operating site, we are required to decommission the site to the satisfaction of the regulators. We have developed conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. Regulators review our conceptual decommissioning plans on a regular basis. As the site approaches or goes into decommissioning, regulators review the detailed decommissioning plans. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.

At the end of 2016, our estimate of total decommissioning and reclamation costs was $1.04 billion. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $894 million at the end of 2016 (the present value of the $1.04 billion). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.

We provide financial assurances for decommissioning and reclamation such as letters of credit to regulatory authorities, as required. We had a total of about $1.0 billion in letters of credit supporting our reclamation liabilities at the end of 2016. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning of the sites.

Some of the sites we own or operate have been under ongoing investigation and/or remediation and planning as a result of historic soil and groundwater conditions. For example, we are addressing issues related to historic soil and groundwater contamination at Port Hope.

We use significant management and financial resources to manage our environmental risks.

We manage environmental risks through our safety, health, environment and quality (SHEQ) management system. Our chief executive officer is responsible for ensuring that our SHEQ management system is implemented. Our board’s safety, health and environment committee also oversees how we manage our environmental risks.

In 2016, we invested:

• |  | $80 million in environmental protection, monitoring and assessment programs, slightly more than in 2015

• |  | $27 million in health and safety programs, or 13% less than 2015 due to major safety improvement programs being completed in 2015

Spending on environmental and health and safety programs is expected to decrease in 2017 as a result of the decisions to transition Rabbit Lake into care and maintenance, and to curtail production at our US operations.

Operational risks

Other operational risks and hazards include:

• |  | environmental damage

• |  | industrial and transportation accidents

• |  | labour shortages, disputes or strikes

• |  | cost increases for labour, contracted or purchased materials, supplies and services

• |  | shortages of required materials, supplies and equipment

• |  | transportation disruptions

• |  | electrical power interruptions

• |  | equipment failures

• |  | non-compliance with laws and licences

• |  | catastrophic accidents

• |  | fires

• |  | blockades or other acts of social or political activism

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 53

• |  | natural phenomena, such as inclement weather conditions, floods and earthquakes

• |  | unusual, unexpected or adverse mining or geological conditions

• |  | underground floods

• |  | ground movement or cave-ins

• |  | tailings pipeline or dam failures

• |  | technological failure of mining methods

• |  | unanticipated consequences of our cost reduction strategies

We have insurance to cover some of these risks and hazards, but not all of them, and not to the full amount of losses or liabilities that could potentially arise.

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Uranium – production overview

Production in our uranium segment in the fourth quarter was 7.1 million pounds, 26% lower compared to the same period in 2015 due to lower production at Inkai, and planned lower production at Rabbit Lake and our US operations, partially offset by an increase in Cigar Lake production. Production for the year was 27.0 million pounds, 5% lower than in 2015 due to the strategic decisions made to suspend production at Rabbit Lake, curtail production at Cameco Resources’ US operations, and reduce production at McArthur River/Key Lake, partially offset by higher than expected production at Cigar Lake. See Uranium - operating properties starting on page 56 for more information.

Uranium production

CAMECO SHARE |  | THREE MONTHS ENDED DECEMBER 31 |  |  | YEAR ENDED DECEMBER 31 |  |  |  |  |  |  |
(MILLION LBS) |  | 2016 |  |  | 2015 |  |  | 2016 |  |  | 2015 |  |  | 2016 PLAN1 |  |  | 2017 PLAN |
McArthur River/Key Lake |  |  | 3.8 |  |  |  | 3.8 |  |  |  | 12.6 |  |  |  | 13.3 |  |  |  | 12.6 |  |  |  | 12.6 |
Cigar Lake |  |  | 2.5 |  |  |  | 2.3 |  |  |  | 8.7 |  |  |  | 5.7 |  |  |  | 8.0 |  |  |  | 9.0 |
Inkai |  |  | 0.7 |  |  |  | 1.1 |  |  |  | 3.4 |  |  |  | 3.4 |  |  |  | 3.0 |  |  |  | 3.1 |
Rabbit Lake |  |  | — |  |  |  | 2.0 |  |  |  | 1.1 |  |  |  | 4.2 |  |  |  | 1.1 |  |  |  | — | 2
Smith Ranch-Highland |  |  | 0.1 |  |  |  | 0.3 |  |  |  | 0.9 |  |  |  | 1.4 |  |  |  | 0.9 |  |  |  | 0.4 | 2
Crow Butte |  |  | — |  |  |  | 0.1 |  |  |  | 0.3 |  |  |  | 0.4 |  |  |  | 0.2 |  |  |  | 0.1 | 2
Total |  |  | 7.1 |  |  |  | 9.6 |  |  |  | 27.0 |  |  |  | 28.4 |  |  |  | 25.8 |  |  |  | 25.2 |

1 | We reduced our initial 2016 production plan to 25.8 million pounds (from 30.0 million pounds) when we announced our operational changes and production curtailment decisions in April, 2016.

2 | The Rabbit Lake operation is in a safe and sustainable state of care and maintenance, and we are no longer developing new wellfields at Crow Butte and Smith Ranch-Highland. Please see Uranium – curtailed operations beginning on page 68 for more information.

Production Outlook

We remain 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 focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to increase long-term shareholder value.

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 all sources of supply and supply expansion opportunities in our portfolio, in order to retain the flexibility to respond to market signals and take advantage of value adding opportunities

• |  | focus on maximizing margins through cost management, productivity improvements, and supply discipline

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 55

Uranium – operating properties

McArthur River mine / Key Lake mill

2016 Production (our share)

12.6M lbs

2017 Production Outlook (our share)

12.6M lbs

Estimated Reserves (our share)

258.1M lbs

Estimated Mine Life

2037

Proportion of 2016 U production

McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the world’s largest uranium mill.

Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator of both the mine and mill.

McArthur River is one of our three material uranium properties.

Location |  | Saskatchewan, Canada
Ownership |  | McArthur River – 69.805%
|  | Key Lake – 83.33%
Mine type |  | Underground
Mining methods |  | Primary: raiseboring, blasthole stoping
|  | Secondary: boxhole boring
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 258.1 million pounds (proven and probable), average grade U3O8: 9.60%
Estimated resources |  | 3.4 million pounds (measured and indicated), average grade U3O8: 3.65%
|  | 7.7 million pounds (inferred), average grade U3O8: 5.20%
Licensed capacity |  | Mine and mill: 25.0 million pounds per year
Licence term |  | Through October, 2023
Total packaged production: |  | 2000 to 2016 |  | 309.1 million pounds (McArthur River/Key Lake) (100% basis)
|  | 1983 to 2002 |  | 209.8 million pounds (Key Lake) (100% basis)
2016 production |  | 12.6 million pounds (18.0 million pounds on 100% basis)
2017 production outlook |  | 12.6 million pounds (18.0 million pounds on 100% basis)
Estimated decommissioning cost |  | $48 million – McArthur River (100% basis)
|  | $218 million – Key Lake (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

BACKGROUND

Mine description

McArthur River currently has six zones with delineated mineral reserves and resources (zones 1 to 4, zones A and B) and one additional area with delineated mineral resources (McArthur north). We are currently mining zone 2 and zone 4.

Zone 2 has been actively mined since production began in 1999. The ore zone was initially divided into three freeze panels (panels 1-2, 3 and 5). As the freeze wall was expanded, the inner connecting freeze walls were decommissioned in order to recover the inaccessible uranium around the active freeze pipes. The majority of the remaining zone 2 mineral reserves are in the upper portion of panel 5.

56 |  | CAMECO CORPORATION |  |

Zone 4 is divided into three mining areas: north, central, and south. We are actively mining the lower central, and north areas. The upper central area is currently in the ground freezing stage, which is expected to be complete in 2017. Similar to zone 2, the inner connecting freeze walls are decommissioned as new panels are brought on line in order to maximize ore recovery.

Zone 1 is under development and freeze hole drilling is in progress. Production from zone 1 is expected to begin in 2020.

We have successfully extracted over 310 million pounds (100% basis) since we began mining in 1999.

Mining methods and techniques

We use a number of innovative methods to mine the McArthur River deposit:

Ground freezing

The sandstone that overlays the deposit and metasedimentary basement rocks is water-bearing and more permeable, which results in significant water pressure at mining depths. In order to isolate the high-pressure water, ground freezing is used to form an impermeable wall around the area being mined. This prevents water from entering the mine, and helps stabilize weak rock formations. To date, we have isolated six mining areas with freeze walls and a seventh mining area is expected to be isolated mid-2017.

Raisebore mining

Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River, and it has been used since mining began in 1999. It involves:

• |  | establishing a drill chamber above the ore and an extraction chamber below the ore

• |  | setting up a raisebore drill in the drill chamber, drilling a pilot hole down to the extraction chamber, attaching a 3-metre wide reaming head to the drill string, and pulling it back up through the ore zone

• |  | collecting the high-grade broken ore at the bottom of the raises using line-of-sight remote-controlled scoop trams, and transporting it to an underground grinding circuit

• |  | filling each raisebore hole with concrete

• |  | when a series of overlapping raisebore holes in a chamber is complete, removing the equipment and filling the entire chamber with concrete

• |  | starting the process again in an adjacent raisebore chamber

Blasthole stoping

Our use of blasthole stoping began in 2011 and has expanded; the majority of ore extraction is now carried out with blasthole stoping. The use of this method has allowed the site to improve operating costs by significantly reducing waste rock handling, backfill dilution, and backfill placement.

Similar to raiseboring, blasthole stoping requires establishing drill access above the ore and extraction access below the ore. Each stope begins with a single raisebore hole (explained above). The stope is then formed by expanding the circumference of the raise by drilling longholes around the raisebore hole and blasting the ore. The blasted material funnels into the raisebore hole and drops to the extraction level below. The broken rock is collected on the lower level and removed by line-of-sight remote-controlled scoop trams, and transported to the underground grinding circuit. Once a stope is mined out, it is backfilled with concrete to maintain ground stability and allow the next stope and/or raise to be mined. This mining method has been used extensively in the mining industry, including uranium mining.

Boxhole boring

Boxhole mining was tested at McArthur River between 2012 and 2015 and though it is approved for use as a mining method, the related costs are higher and it is not being actively used. Boxhole boring is similar to the raisebore method, but the drilling machine is located below the ore, so development is not required above the mineralization.

Initial processing

We carry out initial processing of the extracted ore at McArthur River:

• |  | the underground circuit grinds the ore and mixes it with water to form a slurry

• |  | the slurry is pumped 680 metres to the surface and stored in one of four ore slurry holding tanks

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 57

• |  | it is blended and thickened, removing excess water

• |  | the final slurry, at an average grade of 15% U3O8, is pumped into transport truck containers and shipped to Key Lake mill on an 80 kilometre all-weather road

Water from this process, including water from underground operations, is treated on the surface. Any excess treated water is released into the environment.

Tailings capacity

We expect to have sufficient tailings capacity at Key Lake to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Licensed annual production capacity

The McArthur River mine and Key Lake mill are both licensed to produce up to 25 million pounds (100% basis) per year.

2016 UPDATE

Production

Production from McArthur River/Key Lake was 18.0 million pounds; our share was 12.6 million pounds. This was 6% lower than 2015 and 10% lower than our initial forecast for the year due to our decision to reduce production amid weak market conditions.

Key Lake mill upgrades

The Key Lake mill began operating in 1983 and we have continually upgraded circuits with new technology to simplify operations, improve environmental performance, and allow the mill’s nominal annual production rate to closely follow production from the McArthur River mine. As part of the mill upgrades, a new calciner was installed at the Key Lake mill to accommodate an eventual annual production increase to 25 million pounds. However, reliability issues were encountered with the new equipment during commissioning. Since market conditions do not currently support a decision to increase production, and as part of our continuing efforts to reduce costs, in 2016, we suspended the commissioning of and transition to the new calciner. We are assessing the cost to resolve the issues and expect to complete commissioning if we determine that there is financial and operational value in adding new calcining capacity. The existing calciner has sufficient capacity to meet our 2017 production target of 18 million pounds (12.6 million pounds our share).

New mining areas

We must bring on new mining zones to sustain production, and two new areas are currently under active development: the upper central portion of zone 4, and zone 1. In order to support the development of these zones, infrastructure expansions are required related to freeze capacity and ventilation. In 2016, we completed the upgrade of our surface electrical infrastructure as part of our plan to address current and future needs. We also continued construction of the next freeze plant, which is scheduled to begin freezing the south end of the orebody (zone 4) in 2017.

The mine life of McArthur River/Key Lake has been extended from 2033 to 2037 as a result of changes to the annual production assumptions in our mine plan, and the work completed to upgrade resources to reserves in zone A. See Mineral reserves and resources on page 76 for more information.

Exploration

In 2016, we began underground infill definition drilling of zone B in order to provide the information required for more detailed mining plans.

PLANNING FOR THE FUTURE

Production

Given the current state of oversupply in the uranium market, we plan to produce 18.0 million pounds in 2017; our share is 12.6 million pounds.

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In alignment with our continued efforts to reduce costs, our 2017 production plan for the McArthur River and Key Lake operations includes an extended shut-down during the third quarter, which is expected to result in reduced flight and camp costs. The shut-down will consist of a four-week vacation period, followed by a two-week maintenance period at McArthur River and a four-week maintenance period at Key Lake, with production planned to restart before the end of the third quarter.

We have also planned additional actions for 2017, including a 10% reduction of the workforce at McArthur River and Key Lake, and changes to the commuter flight services at our sites, which are expected to further reduce costs and improve efficiency at the operations.

Expansion potential

We remain 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. Once the market signals that new supply is needed and a decision is made to begin increasing annual production, we will optimize the capacity of both the McArthur River mine and Key Lake mill with a view to achieving annual licensed capacity of 25 million pounds per year (100% basis). We expect that this paced approach will allow us to extract maximum value from the operation as the market transitions.

MANAGING OUR RISKS

Production at McArthur River/Key Lake poses many challenges: control of groundwater, weak rock formations, radiation protection, water inflow, mine area transitioning, and regulatory approvals. Operational experience gained since the start of production has resulted in a significant reduction in risk.

Operational changes

The operational changes we have made, and plan to make in 2017, which are intended to achieve cost savings and improve efficiency, carry with them increased risk of production disruption.

Labour relations

The collective agreement with the United Steelworkers local 8914 expires in December 2017. We plan to begin contract negotiations prior to the expiration of the current agreement. There is a risk to our 2018 production if we are unable to reach agreement and there is a labour dispute.

Transition to new mining areas

In order to successfully achieve the planned production schedule, we must continue to successfully transition into new mining areas, which includes mine development and investment in critical support infrastructure.

Water inflow risk

The greatest risk is production interruption from water inflows. A 2003 water inflow resulted in a three-month suspension of production. We also had a small water inflow in 2008 that did not impact production.

The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

• |  | Ground freezing: Before mining, we drill freezeholes and freeze the ground to form an impermeable freeze wall around the area being mined. Ground freezing reduces but does not eliminate the risk of water inflows.

• |  | Mine development: We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk and apply extensive additional technical and operating controls for all higher risk development.

• |  | Pumping capacity and treatment limits: Our standard for this project is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before beginning work on any new zone.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow.

We also manage the risks listed on pages 52 to 54.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 59

Uranium – operating properties

Cigar Lake

2016 Production (our share)

8.7M lbs

2017 Production Outlook (our share)

9.0M lbs

Estimated Reserves (our share)

107.6M lbs

Estimated Mine Life

2028

Proportion of 2016 U production

Cigar Lake is the world’s highest grade uranium mine, with grades that are 100 times the world average. We are a 50% owner and the mine operator. Cigar Lake uranium is milled at AREVA’s McClean Lake mill.

Cigar Lake is one of our three material uranium properties.

Location |  | Saskatchewan, Canada
Ownership |  | 50.025%
Mine type |  | Underground
Mining method |  | Jet boring system
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 107.6 million pounds (proven and probable), average grade U3O8: 15.90%
Estimated resources |  | 42.3 million pounds (measured and indicated), average grade U3O8: 16.17%
|  | 10.4 million pounds (inferred), average grade U3O8: 7.36%
Licensed capacity |  | 18.0 million pounds per year (our share 9.0 million pounds per year)
Licence term |  | Through June, 2021
Total packaged production: 2014 to 2016 |  | 28.9 million pounds (100% basis)
2016 production |  | 8.7 million pounds (17.3 million pounds on 100% basis)
2017 production outlook |  | 9.0 million pounds (18.0 million pounds on 100% basis)
Estimated decommissioning cost |  | $49 million (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows in 2006 and 2008. The underground workings were successfully remediated and secured in 2011 and in October 2014, the McClean Lake mill produced first uranium concentrate from ore mined at the Cigar Lake operation. Commercial production was declared in May 2015.

Mine description

Cigar Lake’s geological setting is similar to McArthur River’s: the permeable sandstone, which overlays the deposit and basement rocks, contains large volumes of water at significant pressure. However, unlike McArthur River, the Cigar Lake deposit has the shape of a flat- to cigar-shaped lens. As a result of these challenging geological conditions, we are unable to utilize traditional mining methods that require access above the ore, necessitating the development of a non-entry mining method specifically adapted for this deposit: the Jet Boring system (JBS).

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We have begun development below the mineralization and we are currently mining in the eastern part of the ore body (referred to as Phase 1), and surface delineation drilling continues for the western portion (Phase 2).

Mining method

Bulk ground freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, and to prevent water from entering the mine, help stabilize weak rock formations, and meet our production schedule, the ore zone and surrounding ground in the area to be mined must meet specific ground freezing requirements before we begin jet boring.

During construction, development and remediation of the underground infrastructure, we employed a hybrid ground freezing approach using a combination of underground and surface freezing. The costs related to each technique are similar; however, there are significant advantages to freezing the ground from the surface. With surface freezing, less mine development is required, which results in less waste rock and greater ground stability, since freeze tunnels are not required between production tunnels. In addition, congestion is reduced and underground development for freeze infrastructure is no longer a critical path mine activity. Based on these advantages, we have elected to proceed exclusively using surface freezing to mine current mineral reserves at Cigar Lake.

Jet boring system (JBS) mining

After many years of test mining, we selected jet boring, a non-entry mining method, which we have developed and adapted specifically for this deposit. This method involves:

• |  | drilling a pilot hole into the frozen orebody, inserting a high pressure water jet and cutting a cavity out of the frozen ore

• |  | collecting the ore and water mixture (slurry) from the cavity and pumping it to storage (sump storage), allowing it to settle

• |  | using a clamshell, transporting the ore from sump storage to an underground grinding and processing circuit

• |  | once mining is complete, filling each cavity in the orebody with concrete

• |  | starting the process again with the next cavity

We have divided the orebody into production panels and at least three production panels need to be frozen at one time to achieve the full annual production rate of 18 million pounds. One JBS machine will be located below each frozen panel and the three JBS machines required are currently in operation. Two machines can be actively mining at any given time while the third is moving, setting up, or undergoing maintenance.

Initial processing

We carry out initial processing of the extracted ore at Cigar Lake:

• |  | the underground circuit grinds the ore and mixes it with water to form a slurry

• |  | the slurry is pumped 500 metres to the surface and stored in one of two ore slurry holding tanks

• |  | it is blended and thickened, removing excess water

• |  | the final slurry, at an average grade of approximately 16% U3O8, is pumped into transport truck containers and shipped to McClean Lake mill on a 69 kilometre all-weather road

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Water from this process, including water from underground operations, is treated on the surface. Any excess treated water is released into the environment.

Milling

All of Cigar Lake’s ore slurry is being processed at the McClean Lake mill, operated by AREVA. Given the McClean Lake mill’s capacity, it is able to:

• |  | operate at Cigar Lake’s targeted annual production level of 18 million pounds U3O8

• |  | process and package all of Cigar Lake’s current mineral reserves

Licensing annual production capacity

The Cigar Lake mine is licensed to produce up to 18.0 million pounds (100% basis) per year. In 2016, AREVA’s application to increase the licensed capacity of the McClean Lake mill from 13 million to 24 million pounds of annual production was approved by the CNSC.

2016 UPDATE

Production

Total packaged production from Cigar Lake was 17.3 million pounds U3O8; our share was 8.7 million pounds. The operation exceeded our forecast of 16 million pounds (100% basis) as a result of higher productivity and our intention to adjust annual production as necessary, based on our operating experience during rampup.

During the year, we:

• |  | discontinued use of the underground freeze infrastructure and backfilled two redundant crosscuts related to underground freezing

• |  | completed a freeze pad extension to enable surface freeze drilling to resume in 2017

• |  | advanced the freeze plant expansion project through the prefeasibility stage

Underground development

In 2016, we began advancing two new production crosscuts tunnels to ensure we maintain continuous access to frozen ore inventory once mining in the current crosscuts is complete.

McClean Lake mill update

Upgrades to the tails neutralization circuit were substantially completed in 2016, and the mill has sufficient capacity to produce 18 million pounds annually.

Exploration

In 2016, we completed 29,000 metres of diamond drilling as part of the first year of a three-year, 65,000-metre surface drilling program to confirm and upgrade mineral resources contained in the western portion of the deposit (Phase 2). The objective of the program is to complete a detailed geological and geotechnical interpretation, a mineral resource estimate, and a prefeasibility study for Phase 2.

PLANNING FOR THE FUTURE

Production

In 2017, we expect to produce 18.0 million packaged pounds at Cigar Lake; our share is 9.0 million pounds.

In alignment with our continued efforts to reduce costs, our 2017 production plan for the Cigar Lake mine includes an extended shut-down during the third quarter, which is expected to result in reduced flight and camp costs. The shut-down will consist of a four-week vacation period, followed by a two-week maintenance period with mine start-up planned before the end of the third quarter.

We have also planned additional actions for 2017, including a 10% reduction of the workforce at Cigar Lake, changes to the shift rotation schedule, and changes to the commuter flight services at the site, which are expected to further reduce costs and improve efficiency at the operation

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In 2017, we expect to:

• |  | resume surface freeze drilling and advance planning for freeze plant infrastructure expansion in support of future production

• |  | Complete development and outfitting of two additional production crosscuts tunnels according to the mine plan, and backfill two crosscut tunnels where production is complete

McClean Lake mill relicensing

In 2017, AREVA will begin the CNSC relicensing proceedings for its McClean Lake mill. Its existing 8-year licence term ends on June 30, 2017, and it has requested a 12-year licence term as part of its renewal process.

MANAGING OUR RISKS

Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, water inflow, regulatory approvals, surface and underground fires and other mining-related challenges. To reduce this risk, we are applying our operational experience and the lessons we have learned about water inflows at McArthur River and Cigar Lake.

Operational changes

The operational changes we have made, and plan to make in 2017, which are intended to achieve cost savings and improve efficiency, carry with them increased risk of production disruption.

McClean Lake mill relicensing

The McClean Lake mill’s eight year operating licence ends on June 30, 2017, and AREVA has applied for a 12-year renewal. There is risk to our 2017 production if AREVA is unable to secure the licence renewal.

Limited mining experience of the deposit

Although we have now successfully mined a number of cavities, producing a total of 28.9 million pounds, these may not be representative of the deposit as a whole. As we ramp up production, there may be some technical challenges, which could affect our production plans, including, but not limited to, variable or unanticipated ground conditions, ground movement and cave-ins, water inflows and variable dilution, recovery values, chemical ore characteristics, and mining productivity. There is a risk that the ramp up to full production may take longer than planned and that the full production rate may not be achieved on a sustained and consistent basis. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

Ground freezing

To manage our risks and meet our production schedule, the areas being mined must meet specific ground freezing requirements before we begin jet boring. We have identified greater variation of the freeze rates of different geological formations encountered in the mine, based on new information obtained through surface freeze drilling. As a mitigation measure, we have increased the site freeze capacity to facilitate the mining of ore cavities as planned.

Water inflow risk

A significant risk to development and production is from water inflows. The 2006 and 2008 water inflows were significant setbacks.

The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant delay or disruption in Cigar Lake production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

• |  | Bulk freezing: Two of the primary challenges in mining the deposit are control of groundwater and ground support. Bulk freezing reduces but does not completely eliminate the risk of water inflows.

• |  | Mine development: We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk and apply extensive additional technical and operating controls for all higher risk development.

• |  | Pumping capacity and treatment limits: We have pumping capacity to meet our standard for this project of at least one and a half times the estimated maximum inflow.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum inflow.

We also manage the risks listed on pages 52 to 54.

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Uranium – operating properties

Inkai

2016 Production (our share)

3.4M lbs

2017 Production Outlook (our share)

3.1M lbs

Estimated Reserves (our share)

46.3M lbs

Estimated Mine Life

2030 1 (based on licence term)

Proportion of 2016 U production

Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is joint venture Inkai limited liability partnership, which we jointly own (60%) with Kazatomprom (40%)1.

Inkai is one of our three material uranium properties.

Location |  | South Kazakhstan
Ownership |  | 60%1
Mine type |  | In situ recovery (ISR)
End product |  | Uranium concentrate
Certifications |  | BSI OHSAS 18001
|  | ISO 14001 certified
Estimated reserves |  | 46.3 million pounds (proven and probable), average grade U3O8: 0.06%
Estimated resources |  | 81.3 million pounds (measured and indicated), average grade U3O8: 0.06%
|  | 86.2 million pounds (inferred), average grade U3O8: 0.05%
Licensed capacity (wellfields) |  | 5.2 million pounds per year (our share 3.0 million pounds per year)1
Licence term |  | Block 1: 20241, Block 2: 20301, Block 3: 20301
Total packaged production: 2009 to 2016 |  | 40.1 million pounds (100% basis)
2016 production |  | 3.4 million pounds (6.0 million pounds on 100% basis)
2017 production outlook |  | 3.1 million pounds (5.4 million pounds on 100% basis)
Estimated decommissioning cost (100% basis) |  | $10 million (US) (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

1 | We signed an agreement with our partner Kazatomprom and JV Inkai to restructure and enhance JV Inkai. As part of the agreement, subject to closing, our ownership share will be gradually reduced to 40% as production increases, production is expected to increase over time, and the license term for blocks 1, 2 and 3 will be extended, giving JV Inkai the right to produce from all three blocks until 2045. See below for more information.

BACKGROUND

Mine description

The Inkai uranium deposit is a roll-front type orebody within permeable sandstones. The more porous and permeable sand and silt units host several stacked and relatively continuous, sinuous “roll-fronts” of low-grade uranium. There are several uranium deposits and active uranium mines developed along a regional system of superimposed mineralization fronts.

The property is divided into three main areas: two production areas (block 1 and block 2), and an exploration area (block 3):

• |  | The mineralization in block 1 is at a depth of about 500 metres, occurring in a sandstone unit that has a surface projection of about 31 kilometres in length, with an average width of 160 metres

• |  | In block 2, mineralization is mainly in a slightly shallower sandstone unit found between 350 and 420 metres below the surface, with an overall length of about 66 kilometres and an average width of 160 metres

• |  | Exploration work and test wellfield development on block 3 has identified extensive mineralization hosted by several units, traced along a 25 kilometre area beyond block 2.

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Mining and milling method

Inkai uses conventional, well-established, and very efficient in-situ recovery (ISR) technology, developed after extensive test work and operational experience. The process involves five major steps:

• |  | leach the uranium in-situ by circulating an acid-based solution through the host formation

• |  | recover it from solution with ion exchange resin (takes place at both main and satellite processing plants)

• |  | precipitate the uranium with hydrogen peroxide

• |  | thicken, dewater, and dry it

• |  | package the uranium peroxide product in drums.

Production

Total production from Inkai was 6.0 million pounds; our share was 3.4 million pounds, the same as in 2015. The subsoil use law in Kazakhstan allows producers to produce within 20% (above or below) their licensed capacity in a year and as a result, production was 13% higher than its licensed capacity.

Project funding

We are currently advancing funds for Inkai’s work on block 3 and, as of December 31, 2016, the principal and interest amounted to $168 million (US). Under the loan agreement, Inkai is to repay us from the sales proceeds from the sale of its production. On January 20, 2017, a payment of $30 million (US) was received.

2016 JV Inkai Restructuring Agreement

We signed an agreement with our partner Kazatomprom and JV Inkai to restructure and enhance JV Inkai. We currently own a 60% share of JV Inkai while Kazatomprom holds 40%. Based on previous agreements with Kazatomprom, our current interest in production from JV Inkai is 57.5%. The new agreement replaces the memorandum of agreement we signed with Kazatomprom in September 2012 and, subject to closing, provides as follows:

• |  | JV Inkai will have the right to produce 4,000 tonnes of uranium (10.4 million pounds of U3O8) per year (our share 4.2 million pounds), an increase from the current 5.2 million pounds (our share 3.0 million pounds)

• |  | subject to further adjustments tied to the refinery as described below, our ownership interest in JV Inkai will be adjusted to 40%, with Kazatomprom’s share increasing to 60%. However, the agreement ensures that during production rampup, our share of annual production remains at 57.5% on the first 5.2 million pounds. As annual production increases above 5.2 million pounds, we will be entitled to 22.5% of any incremental production, to the maximum annual share of 4.2 million pounds. Once the rampup to 10.4 million pounds annually is complete, our interest in production will be adjusted to match our ownership interest at 40%.

• |  | JV Inkai will have the right to produce from blocks 1, 2 and 3 until 2045 (currently, the lease terms are to 2024 for block 1 and to 2030 for blocks 2 and 3)

• |  | a governance framework that provides protection for us as a minority owner

• |  | the current boundaries of blocks 1, 2 and 3 will be adjusted to match the agreed production profile for JV Inkai to 2045

• |  | the loan that our subsidiary made to JV Inkai to fund exploration and evaluation of block 3 will be restructured to provide for priority repayment

This agreement is subject to obtaining all required government approvals, including certain amendments to JV Inkai’s existing Resource Use Contract, which is expected to take 10 to 18 months. The government approvals are conditional upon submission of certain technical reports and other documents. The agreement provides for annual production at the Inkai operation to be ramped up to 10.4 million pounds U3O8 over three years following receipt of required approvals. Since signing the agreement, we have been working with Kazatomprom and JV Inkai to prepare the various documents required to obtain the necessary government approvals.

We, along with our partner Kazatomprom, will also complete a feasibility study for the purpose of evaluating the design, construction and operation of a uranium refinery in Kazakhstan. The agreement includes provisions that would make our proprietary uranium refining technology available to Kazatomprom on a royalty-free basis, and grants Kazatomprom a five-year option to license our proprietary uranium conversion technology for purposes of constructing and operating a UF6 conversion facility in Kazakhstan.

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If Cameco and Kazatomprom decide to build the refinery, the agreement also provides that:

• |  | our respective ownership interests in the limited liability partnership that will own the refinery will be 71.67% for Kazatomprom and 28.33% for Cameco

• |  | Kazatomprom will have the option to obtain UF6 conversion services at Cameco’s Port Hope facility for a period of 10 years and receive other commercial support

• |  | our ownership interest in JV Inkai is increased to 42.5% upon commissioning of the refinery

Depending on the level of commercial support we provide, our interest in JV Inkai may be increased to 44% and our ownership stake in the refinery partnership would also be adjusted from 28.33% to 29.33%

Caution about forward-looking information relating to the JV Inkai Restructuring Agreement

This discussion of our expectations relating to the JV Inkai restructuring agreement 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

• |  | all required governmental approvals will be received to close and give effect to the contemplated transactions, including approval of the Resource Use Contract amendments from Kazakhstan state authorities, and that these approvals will be received on a timely basis

• |  | JV Inkai will be able to achieve its future annual production targets

• |  | anticipated operations and planned exploration, development and production activities are achieved

Material risks that could cause actual results to differ materially

• |  | all required governmental approvals to close, or give effect to, the contemplated transactions, including approval of the Resource Use Contract amendments from Kazakhstan state authorities, are not received or not received on a timely basis

• |  | JV Inkai is unable to achieve its future annual production targets

• |  | anticipated operations and planned exploration, development and production activities, including any ramp up of JV Inkai’s uranium production, are delayed or not achieved for any reason, including due to operating or technical difficulties, regulatory requirements, or political risk

Block 3 exploration

In 2016, Inkai continued to operate the test leach facility and test wellfields on block 3, which resulted in drummed production of 380,000 pounds (not included in Inkai’s annual production). An amendment to the Resource Use Contract was signed in November, 2016, extending the block 3 exploration period through July 13 2018. Inkai continued working on the final appraisal of the mineral potential of block 3 according to Kazakhstan standards.

PLANNING FOR THE FUTURE

Production

We expect total production from blocks 1 and 2 to be 5.4 million pounds in 2017; our share is 3.1 million pounds.

JV Inkai Restructuring

In 2017, we will continue working with Kazatomprom and JV Inkai to prepare the documents required to close the 2016 JV Inkai Restructuring Agreement. We expect to submit a request for the necessary government approvals in the second half of the year.

Block 3 exploration

In 2017, Inkai expects to continue with pilot production from the test leach facility and to continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

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MANAGING OUR RISKS

Political risk

Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our Inkai investment and plans to increase production are subject to the risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal and fiscal instability. Kazakh laws and regulations are complex and still developing and their application can be difficult to predict. To maintain and increase Inkai production, we need ongoing support, agreement and co-operation from our partner and the government.

The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Subsoil Use Law dated June 24, 2010, as amended (new subsoil law). It replaces the Law on the Subsoil and Subsoil Use, dated January 27, 1996.

In general, Inkai’s licences are governed by the version of the subsoil law that was in effect when the licences were issued in April 1999, and new legislation applies to Inkai only if it does not worsen Inkai’s position. Changes to legislation related to national security, among other criteria, however, are exempt from the stabilization clause in the resource use contract. The Kazakh government interprets the national security exemption broadly.

With the new subsoil law, the government continues to weaken its stabilization guarantee. The government is broadly applying the national security exception to encompass security over strategic national resources.

The resource use contract contains significantly broader stabilization provisions than the new subsoil law, and these contract provisions currently apply to us.

To date, the new subsoil law has not had a significant impact on Inkai. We continue to assess the impact. See our annual information form for an overview of this change in law.

We also manage the risks listed on pages 52 to 54.

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Uranium – curtailed operations

Rabbit Lake

Located in Saskatchewan, Canada, our 100% owned Rabbit Lake operation, which opened in 1975, is the longest operating uranium production facility in North America, and the second largest uranium mill in the world. Given current market conditions, and our belief they will continue to be depressed in the near term, we suspended production at Rabbit Lake during the second quarter of 2016.

PRODUCTION AND PRODUCTION SUSPENSION

Prior to the decision to suspend production, the operation produced 1.1 million pounds in 2016. The facilities are now in a state of safe and sustainable care and maintenance.

The transition to care and maintenance was completed in August, 2016. Care and maintenance costs for the year totaled $55.4 million and related severance totaled $10.6 million, both of which are included in our cost of sales.

A workforce of 120 (down from 650) continues to maintain the facilities, manage ongoing treatment and release of site water effluent, and sustain environmental monitoring and reclamation activities.

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. The estimated decommissioning cost for the Rabbit Lake mine site is $203 million, based on the preliminary decommissioning cost estimate that has been accepted by the Province of Saskatchewan and the CNSC.

IMPAIRMENT

Production was suspended at our Rabbit Lake operation during the second quarter, requiring us to determine the excess carrying value of the mine and mill over the fair value less costs to sell. As a result, we have recognized an impairment charge for the full carrying value of $124 million.

Smith Ranch-Highland & Satellite Facilities, Crow Butte

We operate Crow Butte, and Smith Ranch-Highland. They each have their own processing facilities, but the Highland plant is currently idle.

PRODUCTION AND CURTAILMENT

At Smith Ranch-Highland, production for the year was 36% lower than in 2015. At Crow Butte, 2016 production was 25% lower than in 2015. Production at both operations was lower due to the decision to curtail production in 2016.

The curtailment of Cameco Resources’ US ISR operations resulted in a reduction of 85 positions, including employees and long-term contractors, with a workforce of 160 remaining to operate the sites. The severance cost was $3.6 million, which is included in our cost of sales. The estimated decommissioning costs for our ISR operations are as follows:

• |  | Crow Butte - $46 million (US)

• |  | Smith Ranch-Highland - $188 million (US)

• |  | North Butte - $23 million (US)

The licence for Crow Butte has been renewed. The Nuclear Regulatory Commission license renewal for Smith Ranch - Highland continues.

FUTURE PRODUCTION

Although we have now taken actions to curtail production, due to the nature of ISR mining and our wellfield restoration requirements, production at Smith Ranch-Highland and at Crow Butte is expected to continue, but at a decreasing rate over time as head grade and flow rate declines. In 2017, we expect to produce 0.4 million pounds at Smith Ranch-Highland and 0.1 million pounds at Crow Butte.

MANAGING OUR RISKS

We manage the risks listed on pages 52 to 54.

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Uranium – projects under evaluation

Work on our projects under evaluation has been scaled back and will continue at a pace aligned with market signals.

Millennium

Location |  | Saskatchewan, Canada
Ownership |  | 69.9%
End product |  | Uranium concentrates
Potential mine type |  | Underground
Estimated resources (our share) |  | 53.0 million pounds (indicated), average grade U3O8: 2.39%
|  | 20.2 million pounds (inferred), average grade U3O8: 3.19%

BACKGROUND

The Millennium deposit was discovered in 2000, and was delineated through geophysical survey and surface drilling work between 2000 and 2013. In 2012, we paid $150 million to acquire AREVA’s 27.94% interest in the project, bringing our interest in the project to 69.9%. We are the operator.

Yeelirrie

Location |  | Western Australia
Ownership |  | 100%
End product |  | Uranium concentrates
Potential mine type |  | Open pit
Estimated resources |  | 128.1 million pounds (measured and indicated), average grade U3O8: 0.15%

BACKGROUND

In 2012, we paid $430 million (US) (as well as $22 million (US) in stamp duty) to acquire the Yeelirrie uranium deposit. The deposit was discovered in 1972 and is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.

Kintyre

Location |  | Western Australia
Ownership |  | 70%
End product |  | Uranium concentrates
Potential mine type |  | Open pit
Estimated resources (our share) |  | 37.5 million pounds (indicated), average grade U3O8: 0.62%
|  | 4.2 million pounds (inferred), average grade U3O8: 0.53%

BACKGROUND

In 2008, we paid $346 million (US) to acquire a 70% interest in Kintyre. In 2012, we recorded a $168 million write-down of the carrying value of our interest, due to a weakened uranium market. In 2016, we recorded a further write-down of $238 million for the full carrying value due to weakening of the uranium market since the asset was purchased in 2008, and due to the decision to not allocate any further spending to the project.

The Kintyre deposit is amenable to open pit mining techniques. We are the operator.

2016 PROJECT UPDATES

We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment our primary focus is on uranium production from our tier-one assets. We continue to await a signal from the market that additional production is needed prior to making any new development decisions.

This year, on our projects under evaluation we:

• |  | continued to assess the technical, environmental and financial aspects of each project

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• |  | The Western Australian government granted state environmental approval for the Yeelirrie project, subject to a range of conditions that are considered implementable. We continue to advance the project through the federal environmental assessment process.

• |  | The term of the Yeelirrie State Agreement was extended for a period of 10 years. We now have until 2028 to submit the required mine development and infrastructure proposal to the Western Australian government

PLANNING FOR THE FUTURE

2017 Planned activity

At Yeelirrie, we will undertake efforts to engage agencies in planning research options for subterranean fauna, and implement environmental management plans related to the conditions laid out by Western Australia’s government in their environmental approval of the Yeelirrie project.

At Millennium, no work is planned, as regulatory activity related to our final environmental impact statement continues to be on hold. Further progress towards a development decision is not expected until market conditions improve.

We have no work planned at Kintyre. Although environmental approvals are in place, further progress towards a development decision is not expected until market conditions improve

MANAGING THE RISKS

For all of our projects under evaluation, we manage the risks listed on pages 52 to 54.

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Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral resources as they are depleted by our production, and is key to sustaining our business. We have maintained an active program even during periods of weak uranium prices, which has helped us secure land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia, Kazakhstan and the US. Globally, our land holdings total 1.5 million hectares (3.6 million acres). In northern Saskatchewan alone, we have direct interests in 650,000 hectares (1.6 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin. Many of our prospects are located close to our existing operations where we have established infrastructure and capacity to expand.

For properties that meet our investment criteria, we may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our leadership position and industry expertise in both exploration and corporate social responsibility make us a partner of choice.

In 2016, we continued our exploration strategy of focusing on the most prospective projects in our portfolio. Exploration is key to ensuring our long-term growth.

2016 UPDATE

Brownfield exploration

Brownfield exploration is uranium exploration near our existing operations, and includes expenses for advanced exploration on the evaluation of projects where uranium mineralization is being defined.

In 2016, we spent about $10 million on brownfields and projects under evaluation in Saskatchewan and Australia. At Inkai and our US operations we spent $2 million.

Regional exploration

We spent about $31 million on regional exploration programs (including support costs), primarily in Saskatchewan and Australia.

PLANNING FOR THE FUTURE

We plan to reduce our regional exploration spending by over 35%. We will maintain an active uranium exploration program and continue to focus on our core projects in Saskatchewan under our long-term exploration strategy.

ACQUISITION PROGRAM

We have a dedicated team looking for acquisition opportunities within the nuclear fuel cycle that could further add to our supply, support our sales activities, and complement and enhance our business in the nuclear industry. We will invest when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our shareholders in a fundamentally stronger position.

An acquisition opportunity is never assessed in isolation. Acquisitions must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described in the strategy section, starting on page 13. Currently, given the conditions in the uranium market, and our extensive portfolio of reserves and resources, our focus is on our tier-one assets. We expect that these assets will allow us to meet rising uranium demand with increased production from our best margin operations, and will help to mitigate risk in the event of prolonged uncertainty.

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Fuel services

Refining, conversion and fuel manufacturing

We control about 25% of world UF6 conversion capacity and are a supplier of natural UO2. Our focus is on cost-competitiveness and operational efficiency.

Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and expand our uranium market share.

Blind River Refinery

|  | Licensed Capacity 24.0M kgU of UO3 Licence renewal in Feb, 2022

Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO3.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | UO3
ISO certification |  | ISO 14001 certified
Licensed capacity |  | 18.0 million kgU as UO3 per year, approved to 24.0 million subject to the completion of certain equipment upgrades (advancement depends on market conditions)
Licence term |  | Through February, 2022
Estimated decommissioning cost |  | $48 million (this updated estimate is currently under regulatory review)

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Port Hope Conversion Services

|  | Licensed Capacity 12.5M kgU of UF6 2.8M kgU of UO2 Licence renewal in Feb, 2017

Port Hope is the only uranium conversion facility in Canada and a supplier of UO2 for Canadian-made CANDU reactors.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | UF6, UO2
ISO certification |  | ISO 14001 certified
Licensed capacity |  | 12.5 million kgU as UF6 per year
|  | 2.8 million kgU as UO2 per year
Licence term |  | Through February, 2017
Estimated decommissioning cost |  | $129 million (this updated estimate is currently under regulatory review)

Cameco Fuel Manufacturing Inc. (CFM)

CFM produces fuel bundles and reactor components for CANDU reactors.

Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | CANDU fuel bundles and components
ISO certification |  | ISO 9001 certified, ISO 14001 certified
Licensed capacity |  | 1.2 million kgU as UO2 as finished bundles
Licence term |  | Through February, 2022
Estimated decommissioning cost |  | $21 million (this updated estimate is currently under regulatory review)

2016 UPDATE

Production

Fuel services produced 8.4 million kgU, 13% lower than 2015. This was a result of our decision to decrease production in response to weak market conditions.

Port Hope conversion facility cleanup and modernization (Vision in Motion)

The Vision in Motion project completed the feasibility stage and was part of the relicensing process in 2016. The project will now be undergoing detailed engineering work and some early implementation aspects of the project in 2017.

Labour relations

Approximately 230 unionized employees at the Port Hope conversion facility accepted a new collective agreement. The employees, represented by United Steelworkers locals 13173 and 8562, agreed to a three-year contract that includes a 7% wage increase over the term of the agreement. The previous contract expired on June 30, 2016.

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PLANNING FOR THE FUTURE

Production

The market continues to be weak and as a result, we plan to maintain production between 8 million and 9 million kgU in 2017.

Regulatory

The current operating licence for the Port Hope conversion facility expires in February 2017. The CNSC relicensing process was completed in 2016 and our request for a 10-year operating licence is currently under regulatory review, with the results expected before the end of the current licence term.

MANAGING OUR RISKS

Port Hope conversion facility relicensing

The Port Hope conversion facility’s operating licence ends on February 28, 2017, and we have applied for a 10-year licence renewal. There is a risk to our 2017 conversion production if we are unable to secure the licence renewal.

We also manage the risks listed on pages 52 to 54.

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NUKEM GmbH

Offices |  | Alzenau, Germany (NUKEM GmbH)
|  | Connecticut, US (Subsidiary, NUKEM Inc.)
Ownership |  | 100%
Activity |  | Trading of uranium and uranium-related products
2016 sales1 |  | 7.1 million pounds U3O8
2017 forecast sales |  | 5 to 6 million pounds U3O8

BACKGROUND

In 2013, we acquired NUKEM, one of the world’s leading traders of uranium and uranium-related products. On closing, we paid €107 million ($140 million (US)) and assumed NUKEM’s net debt of about €84 million ($111 million (US)).

NUKEM has access to contracted volumes and inventories in diverse geographic locations as well as scope for opportunistic trading of uranium and uranium-related products. This enables NUKEM to provide a wide range of solutions to its customers that may fall outside the scope of typical uranium sourcing and selling arrangements. Its trading strategy is nonspeculative and seeks to match quantities and pricing structures of its long-term supply and delivery contracts, minimizing exposure to commodity price fluctuations and locking in profit margins.

NUKEM’s main customers are commercial nuclear power plants using enriched uranium fuel, typically large utilities that are either government owned, or large-scale utilities with multibillion-dollar market capitalizations and strong credit ratings. NUKEM also trades with converters, enrichers, other traders and investors.

NUKEM’s business model

NUKEM’s purchase contracts are with long-standing supply partners and its sales contracts are with blue-chip utilities which have strong credit ratings.

MANAGING OUR RISKS

NUKEM manages the risks associated with trading and brokering nuclear fuels and services. It participates in the uranium spot market, making purchases to place material in higher price contracts. There are risks associated with these spot market purchases, including the risk of losses. NUKEM is also subject to counterparty risk of suppliers not meeting their delivery commitments and purchasers not paying for the product delivered. If a counterparty defaults on a payment or other obligation or becomes insolvent, this could significantly affect NUKEM’s contribution to our earnings, cash flows, financial condition or results of operations.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 75

Mineral reserves and resources

Our mineral reserves and resources are the foundation of our company and fundamental to our success.

We have interests in a number of uranium properties. The tables in this section show our estimates of the proven and probable mineral reserves, and measured, indicated, and inferred mineral resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River/Key Lake, Cigar Lake and Inkai.

We estimate and disclose mineral reserves and resources in five categories, using the definitions adopted by the Canadian Institute of Mining, Metallurgy and Petroleum, and in accordance with National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), developed by the Canadian Securities Administrators. You can find out more about these categories at www.cim.org.

About mineral resources

Mineral resources do not have demonstrated economic viability, but have reasonable prospects for eventual economic extraction. They fall into three categories: measured, indicated and inferred. Our reported mineral resources are exclusive of mineral reserves.

• |  | Measured and indicated mineral resources can be estimated with sufficient confidence to allow the appropriate application of technical, economic, marketing, legal, environmental, social and governmental factors to support evaluation of the economic viability of the deposit.

| • |  | measured resources: we can confirm both geological and grade continuity to support detailed mine planning

| • |  | indicated resources: we can reasonably assume geological and grade continuity to support mine planning

• |  | Inferred mineral resources are estimated using limited geological evidence and sampling information. We do not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource, but it is reasonably expected that the majority of inferred mineral resources could be upgraded to indicated mineral resources with continued exploration.

Our share of uranium in the following mineral resource tables is based on our respective ownership interests, except for Inkai which is based on our interest in potential production (57.5%), which differs from our ownership interest (60%). Mineral resources that are not mineral reserves have no demonstrated economic viability.

About mineral reserves

Mineral reserves are the economically mineable part of measured and/or indicated mineral resources demonstrated by at least a preliminary feasibility study. The reference point at which mineral reserves are defined is the point where the ore is delivered to the processing plant, except for ISR operations where the reference point is where the mineralization occurs under the existing or planned wellfield pattern. Mineral reserves fall into two categories:

• |  | proven reserves: the economically mineable part of a measured resource for which at least a preliminary feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified

• |  | probable reserves: the economically mineable part of a measured and/or indicated resource for which at least a preliminary feasibility study demonstrates that, at the time of reporting, economic extraction could be reasonably justified

We use current geological models, constant dollar average uranium prices of $40 to $50 (US) per pound U3O8, depending on the varying production schedules and the annual forecast realized prices, and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.

Our share of uranium in the mineral reserves table below is based on our respective ownership interests, except for Inkai which is based on our interest in planned production (57.5%) assuming an annual production rate of 5.2 million pounds, which differs from our ownership interest (60%).

76 |  | CAMECO CORPORATION |  |

PROVEN AND PROBABLE (P+P) RESERVES, MEASURED AND INDICATED (M+I) RESOURCES, INFERRED RESOURCES

(SHOWING CHANGE FROM 2015)

at December 31, 2016

Changes this year

Our share of proven and probable mineral reserves increased from 410 million pounds U3O8 at the end of 2015, to 415 million pounds at the end of 2016. The change was primarily the result of:

• |  | new and updated mining plans for two zones at McArthur River, which contributed 8 million pounds to proven mineral reserves and 33 million pounds to probable mineral reserves

• |  | revised mineral reserve and resource classifications in Kazakhstan, which resulted in an increase of 27 million pounds in proven mineral reserves, and a decrease of 20 million pounds in probable mineral reserves

partially offset by:

• |  | production, which removed 28 million pounds from our mineral inventory

• |  | conversion of 16 million pounds of reserves to resources, due to economic considerations related to our curtailed US and Rabbit Lake operations

Measured and indicated mineral resources increased from 377 million pounds U3O8 at the end of 2015, to 487 million pounds at the end of 2016. Our share of inferred mineral resources is 248 million pounds U3O8, a decrease of 133 million pounds from the end of 2015. The variance in mineral resources was mainly the result of:

• |  | revised mineral reserve and resource classifications in Kazakhstan, which resulted in increases of 32 million pounds and 19 million pounds in measured and indicated resources respectively, and a decrease of 58 million pounds in inferred resources

• |  | surface delineation drilling at Cigar Lake, resulting in the re-classification of 41 million pounds from inferred to indicated

• |  | delineation drilling at McArthur River to increase geological knowledge, moving 33 million pounds from the inferred to the indicated mineral resources category, subsequently converted to probable reserves

• |  | the reclassification of 16 million pounds of reserves as 18 million pounds of resources, due to economic considerations related to our curtailed US and Rabbit Lake operations

Qualified persons

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

MCARTHUR RIVER/KEY LAKE

• |  | Alain G. Mainville, director, mineral resources management, Cameco

• |  | Greg Murdock, mine manager, McArthur River, Cameco

• |  | Baoyao Tang, technical superintendent, McArthur River, Cameco

• |  | Thomas Saruchera, technical superintendent, Key Lake, Cameco

CIGAR LAKE

• |  | Alain G. Mainville, director, mineral resources management, Cameco

• |  | Leslie Yesnik, general manager, McArthur River/Key Lake, Cameco

• |  | Scott Bishop, manager, technical services, Cameco

INKAI

• |  | Alain G. Mainville, director, mineral resources management, Cameco

• |  | Robert Sumner, principal metallurgist, technical services, Cameco

• |  | Bryan Soliz, principal geologist, Cameco Resources

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 77

Important information about mineral reserve and resource estimates

Although we have carefully prepared and verified the mineral reserve and resource figures in this document, the figures are estimates, based in part on forward-looking information.

Estimates are based on our knowledge, mining experience, analysis of drilling results, the quality of available data and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions, including:

• |  | geological interpretation

• |  | extraction plans

• |  | commodity prices and currency exchange rates

• |  | recovery rates

• |  | operating and capital costs

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 2 for information about forward-looking information.

Please see our mineral reserves and resources section of our annual information form for the specific assumptions, parameters and methods used for McArthur River, Inkai and Cigar Lake mineral reserve and resource estimates.

Important information for US investors

While the terms measured, indicated and inferred mineral resources are recognized and required by Canadian securities regulatory authorities, the US Securities and Exchange Commission (SEC) does not recognize them. Under US standards, mineralization may not be classified as a ‘reserve’ unless it has been determined at the time of reporting that the mineralization could be economically and legally produced or extracted. US investors should not assume that:

• |  | any or all of a measured or indicated mineral resource will ever be converted into proven or probable mineral reserves

• |  | any or all of an inferred mineral resource exists or is economically or legally mineable, or will ever be upgraded to a higher category. Under Canadian securities regulations, estimates of inferred resources may not form the basis of feasibility or pre-feasibility studies. Inferred resources have a great amount of uncertainty as to their existence and economic and legal feasibility.

The requirements of Canadian securities regulators for identification of ‘reserves’ are also not the same as those of the SEC, and mineral reserves reported by us in accordance with Canadian requirements may not qualify as reserves under SEC standards.

Other information concerning descriptions of mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for US domestic mining companies, including Industry Guide 7.

78 |  | CAMECO CORPORATION |  |

Mineral reserves

As at December 31, 2016 (100% basis – only the shaded column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

|  |  |  |  | PROVEN |  |  | PROBABLE |  |  | TOTAL MINERAL RESERVES |  |  | OUR SHARE RESERVES |  |  | METALLURGICAL RECOVERY (%) |
PROPERTY |  | MINING METHOD |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | CONTENT (LBS U3O8) |  |
Cigar Lake |  |  | UG |  |  |  | 209.6 |  |  |  | 19.86 |  |  |  | 91.8 |  |  |  | 403.8 |  |  |  | 13.84 |  |  |  | 123.2 |  |  |  | 613.4 |  |  |  | 15.90 |  |  |  | 215.0 |  |  |  | 107.6 |  |  |  | 98.5 |
Key Lake |  |  | OP |  |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 98.7 |
McArthur River |  |  | UG |  |  |  | 1,184.9 |  |  |  | 9.57 |  |  |  | 250.1 |  |  |  | 562.5 |  |  |  | 9.64 |  |  |  | 119.5 |  |  |  | 1,747.4 |  |  |  | 9.60 |  |  |  | 369.7 |  |  |  | 258.1 |  |  |  | 98.7 |
Crow Butte |  |  | ISR |  |  |  | 583.0 |  |  |  | 0.03 |  |  |  | 0.4 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 583.0 |  |  |  | 0.03 |  |  |  | 0.4 |  |  |  | 0.4 |  |  |  | 85 |
Inkai |  |  | ISR |  |  |  | 33,193.4 |  |  |  | 0.07 |  |  |  | 48.6 |  |  |  | 30,717.0 |  |  |  | 0.05 |  |  |  | 32.0 |  |  |  | 63,910.3 |  |  |  | 0.06 |  |  |  | 80.6 |  |  |  | 46.3 |  |  |  | 85 |
North Butte - Brown Ranch |  |  | ISR |  |  |  | 364.5 |  |  |  | 0.08 |  |  |  | 0.7 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 364.5 |  |  |  | 0.08 |  |  |  | 0.7 |  |  |  | 0.7 |  |  |  | 60 |
Smith Ranch - Highland |  |  | ISR |  |  |  | 444.7 |  |  |  | 0.10 |  |  |  | 1.0 |  |  |  | 34.2 |  |  |  | 0.13 |  |  |  | 0.1 |  |  |  | 478.9 |  |  |  | 0.10 |  |  |  | 1.1 |  |  |  | 1.1 |  |  |  | 80 |
Total |  |  |  |  |  |  | 36,041.2 |  |  |  | — |  |  |  | 393.3 |  |  |  | 31,717.5 |  |  |  | — |  |  |  | 274.8 |  |  |  | 67,758.7 |  |  |  | — |  |  |  | 668.1 |  |  |  | 414.7 |  |  |  | — |

(UG – underground, OP – open pit, ISR – in situ recovery, totals may not add up due to rounding.

Note that the estimates in the above table:

• |  | use constant dollar average uranium prices, varying over time, from $40 to $50 (US)/lb U3O8

• |  | are based on an average exchange rate of $1.00 US=$1.20 to $1.25 Cdn

Our estimate of mineral reserves and mineral resources may be positively or negatively affected by the occurrence of one or more the material risks discussed under the heading Caution about forward-looking information beginning on page 2, as well as certain property-specific risks. See Uranium - operating properties starting on page 56

Metallurgical recovery

We report mineral reserves as the quantity of contained ore supporting our mining plans, and provide an estimate of the metallurgical recovery for each uranium property. The estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process is obtained by multiplying quantity of contained metal (content) by the planned metallurgical recovery percentage. The content and our share of uranium in the table above are before accounting for estimated metallurgical recovery.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 79

Mineral resources

As at December 31, 2016 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

|  | MEASURED RESOURCES (M) |  |  | INDICATED RESOURCES (I) |  |  | TOTAL M+I CONTENT (LBS U3O8) |  |  | OUR SHARE TOTAL M+I CONTENT (LBS U3O8) |  |  | INFERRED RESOURCES |  |  | OUR SHARE INFERRED CONTENT (LBS U3O8) |
PROPERTY |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |
Cigar Lake |  |  | 1.3 |  |  |  | 4.71 |  |  |  | 0.1 |  |  |  | 235.7 |  |  |  | 16.24 |  |  |  | 84.4 |  |  |  | 84.5 |  |  |  | 42.3 |  |  |  | 128.4 |  |  |  | 7.36 |  |  |  | 20.8 |  |  |  | 10.4 |
Fox Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 386.7 |  |  |  | 7.99 |  |  |  | 68.1 |  |  |  | 53.3 |
Kintyre |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,897.7 |  |  |  | 0.62 |  |  |  | 53.5 |  |  |  | 53.5 |  |  |  | 37.5 |  |  |  | 517.1 |  |  |  | 0.53 |  |  |  | 6.0 |  |  |  | 4.2 |
McArthur River |  |  | 43.4 |  |  |  | 4.36 |  |  |  | 4.2 |  |  |  | 16.8 |  |  |  | 1.79 |  |  |  | 0.7 |  |  |  | 4.8 |  |  |  | 3.4 |  |  |  | 95.9 |  |  |  | 5.20 |  |  |  | 11.0 |  |  |  | 7.7 |
Millennium |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,442.6 |  |  |  | 2.39 |  |  |  | 75.9 |  |  |  | 75.9 |  |  |  | 53.0 |  |  |  | 412.4 |  |  |  | 3.19 |  |  |  | 29.0 |  |  |  | 20.2 |
Wheeler River |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 166.4 |  |  |  | 19.13 |  |  |  | 70.2 |  |  |  | 70.2 |  |  |  | 21.1 |  |  |  | 842.5 |  |  |  | 2.38 |  |  |  | 44.1 |  |  |  | 13.2 |
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,281.5 |  |  |  | 0.79 |  |  |  | 39.7 |  |  |  | 39.7 |  |  |  | 39.7 |  |  |  | 2,631.4 |  |  |  | 0.58 |  |  |  | 33.6 |  |  |  | 33.6 |
Tamarack |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 17.9 |  |  |  | 10.3 |  |  |  | 45.6 |  |  |  | 1.02 |  |  |  | 1.0 |  |  |  | 0.6 |
Yeelirrie |  |  | 27,172.9 |  |  |  | 0.16 |  |  |  | 95.9 |  |  |  | 12,178.3 |  |  |  | 0.12 |  |  |  | 32.2 |  |  |  | 128.1 |  |  |  | 128.1 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Crow Butte |  |  | 1,418.2 |  |  |  | 0.21 |  |  |  | 6.6 |  |  |  | 1,354.9 |  |  |  | 0.29 |  |  |  | 8.6 |  |  |  | 15.2 |  |  |  | 15.2 |  |  |  | 1,135.2 |  |  |  | 0.12 |  |  |  | 2.9 |  |  |  | 2.9 |
Gas Hills-Peach |  |  | 687.2 |  |  |  | 0.11 |  |  |  | 1.7 |  |  |  | 3,626.1 |  |  |  | 0.15 |  |  |  | 11.6 |  |  |  | 13.3 |  |  |  | 13.3 |  |  |  | 3,307.5 |  |  |  | 0.08 |  |  |  | 6.0 |  |  |  | 6.0 |
Inkai |  |  | 34,855.4 |  |  |  | 0.07 |  |  |  | 55.3 |  |  |  | 77,914.4 |  |  |  | 0.05 |  |  |  | 86.0 |  |  |  | 141.3 |  |  |  | 81.3 |  |  |  | 151,583.1 |  |  |  | 0.05 |  |  |  | 149.9 |  |  |  | 86.2 |
North Butte-Brown Ranch |  |  | 604.2 |  |  |  | 0.08 |  |  |  | 1.1 |  |  |  | 5,530.3 |  |  |  | 0.07 |  |  |  | 8.4 |  |  |  | 9.4 |  |  |  | 9.4 |  |  |  | 294.5 |  |  |  | 0.07 |  |  |  | 0.4 |  |  |  | 0.4 |
Ruby Ranch |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 56.2 |  |  |  | 0.14 |  |  |  | 0.2 |  |  |  | 0.2 |
Shirley Basin |  |  | 89.2 |  |  |  | 0.16 |  |  |  | 0.3 |  |  |  | 1,638.2 |  |  |  | 0.11 |  |  |  | 4.1 |  |  |  | 4.4 |  |  |  | 4.4 |  |  |  | 508.0 |  |  |  | 0.10 |  |  |  | 1.1 |  |  |  | 1.1 |
Smith Ranch-Highland |  |  | 3,354.0 |  |  |  | 0.10 |  |  |  | 7.1 |  |  |  | 14,338.1 |  |  |  | 0.05 |  |  |  | 16.9 |  |  |  | 24.0 |  |  |  | 24.0 |  |  |  | 6,861.0 |  |  |  | 0.05 |  |  |  | 7.7 |  |  |  | 7.7 |
Total |  |  | 68,225.8 |  |  |  | — |  |  |  | 172.3 |  |  |  | 127,020.2 |  |  |  | — |  |  |  | 514.1 |  |  |  | 686.4 |  |  |  | 487.0 |  |  |  | 168,805.5 |  |  |  | — |  |  |  | 382.0 |  |  |  | 247.9 |

Totals may not add up due to rounding.

Note that mineral resources:

• |  | do not include amounts that have been identified as mineral reserves

• |  | do not have demonstrated economic viability

80 |  | CAMECO CORPORATION |  |

Additional information

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.

We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements. These estimates affect all of our segments, unless otherwise noted.

Decommissioning and reclamation

In our uranium and fuel services segments, we are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position. See note 15 to the financial statements.

Property, plant and equipment

We depreciate property, plant and equipment primarily using the unit-of-production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.

We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.

In performing impairment assessments of long-lived assets, assets that cannot be assessed individually are grouped together into the smallest group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Management is required to exercise judgment in identifying these cash generating units.

Taxes

When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation of deferred tax assets, changes in tax laws and our expectations for future results.

We base our estimates of deferred income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record deferred income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses, future market conditions, production levels and intercompany sales. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.

Commencement of production stage

When we determine that a mining property has reached the production stage, capitalization of development ceases, and depreciation of the mining property begins and is charged to earnings. Production is reached when management determines that the mine is able to produce at a consistent or sustainably increasing level. This determination is a matter of judgment. See note 2 to the financial statements for further information on the criteria that we used to make this assessment.

|  | MANAGEMENT’S DISCUSSION AND ANALYSIS |  | 81

Purchase price allocations

The purchase price related to a business combination or asset acquisition is allocated to the underlying acquired assets and liabilities based on their estimated fair values at the time of acquisition. The determination of fair value requires us to make assumptions, estimates and judgments regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation impacts our reported assets and liabilities and future net earnings due to the impact on future depreciation and amortization expense and impairment tests.

Determination of joint control

We conduct certain operations through joint ownership interests. Judgment is required in assessing whether we have joint control over the investee, which involves determining the relevant activities of the arrangement and whether decisions around relevant activities require unanimous consent. Judgment is also required to determine whether a joint arrangement should be classified as a joint venture or joint operation. Classifying the arrangement requires us to assess our rights and obligations arising from the arrangement. Specifically, management considers the structure of the joint arrangement and whether it is structured through a separate vehicle. When structured through a separate vehicle, we also consider the rights and obligations arising from the legal form of the separate vehicle, the terms of the contractual arrangements and other facts and circumstances, when relevant. This judgment influences whether we equity account or proportionately consolidate our interest in the arrangement.

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2016, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

Management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that, while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2016. We have not made any change to our internal control over financial reporting during the 2016 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New standards and interpretations not yet adopted

A number of new standards and amendments to existing standards are not yet effective for the year ended December 31, 2016, and have not been applied in preparing these consolidated financial statements. Cameco does not intend to early adopt any of the following standards or amendments to existing standards, unless otherwise noted.

IFRS 15, Revenue from Contracts with Customers (IFRS 15) – In May 2014, the IASB issued IFRS 15 which is effective for periods beginning on or after January 1, 2018 and is to be applied retrospectively. IFRS 15 clarifies the principles for recognizing revenue from contracts with customers. Cameco does not expect the standard to have a material impact on the financial statements.

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IFRS 9, Financial Instruments (IFRS 9) – In July 2014, the IASB issued IFRS 9. IFRS 9 replaces the existing guidance in IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 includes revised guidance on the classification and measurement of financial assets, a new expected credit loss model for calculating impairment on financial assets and new hedge accounting requirements. It also carries forward, from IAS 39, guidance on recognition and derecognition of financial instruments.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early adoption of the new standard permitted. Cameco does not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

IFRS 16, Leases (IFRS 16) – In January 2016, the IASB issued IFRS 16 which is effective for periods beginning on or after January 1, 2019, with early adoption permitted. IFRS 16 eliminates the current dual model for lessees, which distinguishes between on-balance sheet finance leases and off-balance sheet operating leases. Instead, there is a single, on-balance sheet accounting model that is similar to current finance lease accounting. The extent of the impact of adoption of IFRS 16 has not yet been determined.

In January 2017, the IASB issued Disclosure Initiative (Amendments to IAS 7). The standard applies prospectively and is effective for annual periods beginning on or after January 1, 2017, with earlier application permitted. The amendments require disclosures that enable users of financial statements to evaluate changes in liabilities arising from financing activities, including both changes arising from cash flow and non-cash changes. Cameco does not expect the amendments to have a material impact on the financial statements.

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