EX-4 5 d479791dex4.htm EX-4

Management’s discussion and analysis

February 9, 2018

6 |  | 2017 PERFORMANCE HIGHLIGHTS
9 |  | MARKET OVERVIEW AND 2017 DEVELOPMENTS
13 |  | OUR STRATEGY
21 |  | MEASURING OUR RESULTS
22 |  | FINANCIAL RESULTS
51 |  | OPERATIONS AND PROJECTS
74 |  | MINERAL RESERVES AND RESOURCES
79 |  | 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, 2017. The information is based on what we knew as of February 7, 2018.

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 2018 and future global uranium supply, consumption, demand, contracting volumes and number of reactors, including the discussion under the heading Market overview and 2017 developments

| • |  | the discussion under the heading Our strategy

| • |  | our expectations for uranium deliveries in 2018

| • |  | the discussion of our expectations relating to our Canada Revenue Agency (CRA) transfer pricing dispute, 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 expectations that we will recognize a gain in the first quarter of approximately $66 million on the change of Joint Venture Inkai LLP’s (JV Inkai) ownership interest

| • |  | our consolidated outlook for the year and the outlook for our uranium and fuel services segments for 2018

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

| • |  | our price sensitivity analysis for our uranium segment

| • |  | our expectation that existing cash balances and operating cash flows will meet our anticipated 2018 capital requirements

| • |  | our expectations for 2018, 2019 and 2020 capital expenditures

| • |  | our expectation that in 2018 we will be able to comply with all the covenants in our unsecured revolving credit facility

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

| • |  | our expectations related to 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, loss of market share to a competitor or trade restrictions

| • |  | 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, decommissioning, reclamation expenses, or our tax expense 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 dispute with CRA or with TEPCO

| • |  | our estimate of the gain on the change in ownership interests for JV Inkai prove to be inaccurate

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

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

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

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

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

| • |  | necessary permits or approvals from government authorities cannot be obtained or maintained

| • |  | we are affected by political risks

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

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

2 CAMECO CORPORATION

| • |  | 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 and/or Cigar Lake development, mining or production plans are delayed or do not succeed for any reason

| • |  | any difficulties in resuming McArthur River production after the end of the production suspension including as a result of failure to reach a new collective agreement

| • |  | any difficulties in milling of Cigar Lake ore at the McClean Lake mill or resuming production after the extended Cigar Lake shutdown scheduled for the third quarter

| • |  | JV Inkai’s development, mining or production plans are delayed or do not succeed for any reason

| • |  | our expectations relating to 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, trade restrictions and that counterparties to our sales and purchase agreements will honour their commitments

| • |  | our expectations regarding the demand for and supply of uranium

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

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

| • |  | our expected production level

| • |  | our cost expectations, including production costs, purchase costs and the success of our cost reduction strategies

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

| • |  | the accounting treatment for the change in ownership interests in JV Inkai is as expected

| • |  | our expectations about the outcome of disputes with CRA 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 uranium properties

| • |  | our McArthur River development, mining and production plans succeed, including the resumption of production after the end of the production suspension

| • |  | our Cigar Lake development, mining and production plans succeed, including the resumption of production after the end of the extended shutdown scheduled for the third quarter

| • |  | the McClean Lake mill is able to process Cigar Lake ore as expected

| • |  | that care and maintenance costs will be as expected

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 3

2017 performance highlights

Our focus throughout 2017 continued to be on lowering our costs and improving efficiency amid ongoing 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 that shift emerge, we will continue to take the necessary actions intended to shield the company from the nearer-term risks we face and that we expect will reward shareholders for their continued patience and support of our strategy to build long-term value.

Financial performance

HIGHLIGHTS |  |  |  |  |  |  |  |  |
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2017 |  |  | 2016 |  |  | CHANGE |
Revenue |  |  | 2,157 |  |  |  | 2,431 |  |  |  | (11)% |
Gross profit |  |  | 436 |  |  |  | 463 |  |  |  | (6)% |
Net loss attributable to equity holders |  |  | (205 | ) |  |  | (62 | ) |  |  | >(100%) |
$ per common share (diluted) |  |  | (0.52 | ) |  |  | (0.16 | ) |  |  | >(100%) |
Adjusted net earnings (non-IFRS, see page 24) |  |  | 59 |  |  |  | 143 |  |  |  | (59)% |
$ per common share (adjusted and diluted) |  |  | 0.15 |  |  |  | 0.36 |  |  |  | (58)% |
Cash provided by operations (after working capital changes) |  |  | 596 |  |  |  | 312 |  |  |  | 91% |

Net loss attributable to equity holders (net loss) and adjusted net earnings were lower in 2017 compared to 2016, in-line with the outlook we provided. See 2017 consolidated financial results beginning on page 23 for more information.

Our uranium segment continued to outperform the market

In our uranium segment, annual production was slightly below expectations as a result of both planned and unplanned reductions. Key highlights:

| • |  | annual production of 23.8 million pounds—1% lower than the guidance provided in our 2017 third quarter MD&A

| • |  | quarterly production of 6.9 million pounds in the fourth quarter—3% lower than in 2016 due to the curtailment of production at the US operations, lower production at Inkai and from McArthur River/Key Lake

| • |  | achieved ramp up to full production at the Cigar Lake mine and Orano’s (formerly AREVA) McClean Lake mill

| • |  | closed the agreement with our partner Kazatomprom and JV Inkai to restructure and enhance JV Inkai

| • |  | successfully implemented operational changes at our mining operations resulting in capital and operating cost savings

| • |  | announced the temporary production suspension at McArthur River/Key Lake commencing in 2018

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

Updates on our other segments and investments

Production in 2017 from our fuel services segment was 6% lower than in 2016, as planned, due to weak market conditions for conversion services.

In 2017, the Canadian Nuclear Safety Commission (CNSC) approved a 10-year operating licence for Port Hope.

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HIGHLIGHTS |  |  |  | 2017 |  |  | 2016 |  |  | CHANGE |
Uranium |  | Production volume (million lbs) |  |  |  |  | 23.8 |  |  |  | 27.0 |  |  |  | (12 | )%
|  | Sales volume (million lbs)1 |  |  |  |  | 33.6 |  |  |  | 31.5 |  |  |  | 7 | %
|  | Average realized price |  | ($US/lb) |  |  | 36.13 |  |  |  | 41.12 |  |  |  | (12 | )%
|  |  |  | ($Cdn/lb) |  |  | 46.80 |  |  |  | 54.46 |  |  |  | (14 | )%
|  | Revenue ($ millions)1 |  |  |  |  | 1,574 |  |  |  | 1,718 |  |  |  | (8 | )%
|  | Gross profit ($ millions) |  |  |  |  | 395 |  |  |  | 444 |  |  |  | (11 | )%
Fuel services |  | Production volume (million kgU) |  |  |  |  | 7.9 |  |  |  | 8.4 |  |  |  | (6 | )%
|  | Sales volume (million kgU)1 |  |  |  |  | 11.5 |  |  |  | 12.7 |  |  |  | (9 | )%
|  | Average realized price |  | ($Cdn/kgU) |  |  | 27.20 |  |  |  | 25.37 |  |  |  | 7 | %
|  | Revenue ($ millions)1 |  |  |  |  | 313 |  |  |  | 321 |  |  |  | (2 | )%
|  | Gross profit ($ millions) |  |  |  |  | 64 |  |  |  | 63 |  |  |  | 2 | %
NUKEM |  | Sales volume U3O8 (million lbs)1 |  |  |  |  | 10.0 |  |  |  | 7.1 |  |  |  | 41 | %
|  | Average realized price |  | ($Cdn/lb) |  |  | 32.25 |  |  |  | 47.90 |  |  |  | (33 | )%
|  | Revenue ($ millions)1 |  |  |  |  | 321 |  |  |  | 391 |  |  |  | (18 | )%
|  | Gross loss ($ millions)2 |  |  |  |  | (15 | ) |  |  | (28 | ) |  |  | 46 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments. Please see 2017 Financial results by segment beginning on page 41.

2 | Gross loss includes net inventory write-downs of $9 million in 2017 and $18 million in 2016 due to a decline in the spot price during the year.

Industry prices

In 2017, the uranium spot price ranged from a high of $24.50 (US) per pound to a low of about $19 (US) per pound, averaging around $22 (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 discretionary in 2018.

|  | 2017 |  |  | 2016 |  |  | CHANGE |
Uranium ($US/lb U3O8)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  | 21.78 |  |  |  | 25.64 |  |  |  | (15 | )%
Average annual long-term price |  |  | 31.92 |  |  |  | 39.00 |  |  |  | (18 | )%
Fuel services ($US/kgU as UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average annual spot market price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 5.26 |  |  |  | 6.40 |  |  |  | (18 | )%
Europe |  |  | 5.69 |  |  |  | 6.91 |  |  |  | (18 | )%
Average annual long-term price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 14.00 |  |  |  | 12.58 |  |  |  | 11 | %
Europe |  |  | 14.04 |  |  |  | 13.56 |  |  |  | 4 | %

Note: the industry does not publish UO2 prices.

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

Also of note

TEPCO contract dispute

On January 31, 2017, 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 is pursuing all its legal rights and remedies against TEPCO.

MANAGEMENT’S DISCUSSION AND ANALYSIS 7

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.

Three arbitrators have been appointed and based on the current schedule set by them, we expect the case will be heard in the first quarter of 2019. We are seeking $682 million (US) in damages plus interest and legal costs. The $682 million (US) primarily represents the present value of the remaining contracted volumes at the January 2017 contract price less the January 2017 market price of the equivalent volume of uranium concentrates.

The timing for a final decision will be dependent on how long the arbitrators deliberate following the conclusion of the hearing.

In this MD&A, our 2018 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.

JV Inkai restructuring

On December 11, 2017, we announced that the restructuring of JV Inkai outlined in the implementation agreement dated May 27, 2016 with Kazatomprom and JV Inkai closed and would take effect on January 1, 2018. Our ownership interest in JV Inkai is now 40% and Kazatomprom’s is 60%. As a result, we will account for JV Inkai on an equity basis commencing on January 1, 2018.

In addition, we will recognize a gain on the change in ownership interests of approximately $66 million. The resulting gain on restructuring will be reflected in our financial results for the first quarter.

SHARES AND STOCK OPTIONS OUTSTANDING

At February 7, 2018, we had:

| • |  | 395,792,732 common shares and one Class B share outstanding

| • |  | 8,322,866 stock options outstanding, with exercise prices ranging from $14.70 to $39.53

DIVIDEND

In 2017, our board of directors reduced the planned dividend to $0.08 per common share to be paid annually. The decision to declare a dividend by our board will be based on our cash flow, financial position, strategy and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

8 CAMECO CORPORATION

Market overview and 2017 developments

Cautiously optimistic

Despite the ongoing market challenges in 2017, we remain cautiously optimistic. We are cautious because we continue to face difficult market conditions and have seen a reduction in global demand expectations, driven by early reactor retirements, delays in reactor construction programs and by changes in governments that have created additional uncertainty for the nuclear industry. At the same time, the industry continues to work its way through supply that was incented during previous price runs. However, we are optimistic because today’s uranium prices are too low to motivate even some of the lowest-cost, profit-driven producers to maintain existing production, let alone invest in new projects that we believe will be required to ensure adequate uranium production is in the market. Additional uranium supply will be needed to support the reactor construction programs currently underway but not yet consuming uranium, the return of idled reactors to the grid, and to satisfy utilities uncovered requirements.

2017: A STORY OF OVERSUPPLY

In 2017, excess uranium supply continued to have a significant impact on the uranium market. Abundant spot material was available to satisfy utilities’ appetite for low-priced pounds to meet near- to mid-term requirements.

Secondary supplies, consisting largely of government inventories, enricher underfeeding and tails re-enrichment, where the economics differ considerably from mined production, have been a significant contributor to the supply-demand imbalance in the market. In addition, supply from some producers, whose production decisions are not necessarily driven by the economics of the uranium market, such as large diversified miners and companies mining uranium for strategic or social purposes, has been a contributor to the imbalance. 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. However, in 2017, we started to see evidence that at today’s low uranium prices, not only is some of the higher cost production at risk, even the lowest-cost production faces planned and unplanned risks.

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 five years only 320 million pounds have been locked-up in the long-term market, while over 788 million pounds have been consumed in reactors, we remain confident that utilities have a growing gap to fill. As annual supply adjusts and utilities’ annual uncovered requirements grow, we believe the pounds available in the spot market won’t be enough to satisfy demand in the long run.

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.

We believe 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 730 million pounds over the next ten years. While annual 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. Not only is there a lack of investment in future supply – we are seeing evidence that existing supply is at risk. Higher-cost producers who have been protected from the low market prices under long-term contracts, are beginning to emerge from that protection, some cutting production, and others having to be recapitalized or seeking protection from bankruptcy. Even the lowest-cost producers are deciding to preserve long-term value by leaving uranium in the ground. Overall, based on a number of developments throughout the year, global production is expected to decrease:

| • |  | In addition to the curtailments at Rabbit Lake and in the US in 2016, we announced our plan to temporarily suspend production at the McArthur River/Key Lake operation in 2018, removing 18 million pounds from the market.

| • |  | In November, Kazatomprom announced its 2017 uranium production in Kazakhstan would be about 58 million pounds, about 10% less than the nearly 64 million pounds produced in 2016, and in-line with the planned reduction target it announced in January of 2017. In December, it announced a 20% reduction in planned production for 2018 through 2020, which it indicated will result in production volumes similar to 2017.

| • |  | Paladin entered administration seeking to restructure and recapitalize due to its inability to meet its debt repayment obligations.

| • |  | Orano, who was recapitalized by the French government, announced plans to cut production at its Somair mine in Niger in 2018, and along with us, agreed to the temporary suspension of production at McArthur River/Key Lake in 2018.

10 CAMECO CORPORATION

| • |  | Multiple US ISR projects announced output reductions in 2018.

| • |  | In 2017, reports regarding production at the Husab mine in Namibia continued to raise uncertainty about the timing and even the possibility of reaching name-plate capacity of 15 million pounds annually.

| • |  | In the conversion space, earlier in the year, Honeywell announced a capacity reduction, which was followed by an announcement at the end of the year of its plans to temporarily idle its Metropolis site until business conditions improve.

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.

DEMAND SIDE DEVELOPMENTS

There was mixed news for the broader nuclear industry in 2017. On a regional demand basis, some of the more significant positive and negative developments were:

| • |  | As part of Bruce Power’s commitment to refurbish its CANDU reactors, in 2017 Bruce Power signed an agreement worth approximately $2 billion with us to extend its fuel supply agreement to 2030.

| • |  | The US division of Westinghouse Electric Company declared bankruptcy, ultimately resulting in the pending abandonment of the two V.C. Summer units under construction in South Carolina. However, completion of the Vogtle units in Georgia was approved.

| • |  | Several additional early reactor retirements were announced in the US due to high costs. However, efforts are being made in several states to enact incentives to support the continued operation of nuclear plants, an issue that has also been taken up at the federal level.

| • |  | In January 2018, two US uranium producers put forward a petition under Section 232 of the Trade Expansion Act due to pressures from state-sponsored (Russia, Kazakhstan, Uzbekistan and China) imports. The petition aims to have 25% of US nuclear reactor requirements sourced from the US and a Buy America policy for US government agencies. Currently less than 5% of US requirements are met by US uranium producers.

| • |  | China continued to face challenges from excess capacity in the energy sector and first-of-a-kind reactor delays on its AP1000 and EPR reactors. However, with Xi Jinping continuing as President of China we believe China will continue with its nuclear growth ambitions. A recent report quotes a Bloomberg analyst who anticipates that nuclear installed capacity could increase tenfold between 2016 and 2050 to over 300 GW in China.

| • |  | South Korea’s new government announced its plan to phase-out nuclear power. However, a public panel voted in favour of completing the two reactors under construction that the government had previously suspended.

| • |  | In France, the new government reaffirmed its commitment to reduce its reliance on nuclear by 2025, but later acknowledged that target as unrealistic, postponing the reduction until the 2030 to 2035 timeframe.

| • |  | Construction on the first nuclear plants in Turkey and Bangladesh was started.

| • |  | Egypt signed a contract with Russia to build four reactors.

| • |  | Saudi Arabia is working to prequalify reactor vendors as it moves forward with plans for its first nuclear power plant, marking progress on its ambitions to install 17 gigawatts of nuclear capacity by 2040.

While 2017 offered some 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, with the restart of five reactors and another four expected to restart in 2018.

| • |  | In 2017, there were four new reactors connected to the grid. Currently there are 57 reactors under construction around the world, the majority of which are expected to come online in the next three years, if startups occur as planned.

| • |  | There is a growing acknowledgment that adherence to global climate change goals requires a material dedication to all non-emitting energy sources, including nuclear. The World Nuclear Associations target of 25% nuclear in 2050 is an example of this movement. Additionally, as a result of the closure of its nuclear plants, Germany has acknowledged that it will no longer be able to meet its climate goals despite its substantial rollout of renewable energy under the government’s policy.

MANAGEMENT’S DISCUSSION AND ANALYSIS 11

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 declining 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 and is 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.

12 CAMECO CORPORATION

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, electricity demand and clean air concerns.

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 preserve the value of those assets and 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. In accordance with market conditions, and to mitigate risk, we will evaluate the optimal mix of our production, inventory and purchases in order to satisfy our contractual commitments and in order to return the best value possible. During a prolonged period of uncertainty, this could mean leaving our uranium in the ground. 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 focused on preserving the value of our lowest cost assets, on maintaining a strong balance sheet, on protecting and extending the value of our contract portfolio and on efficiently managing the company in a low price environment. We have undertaken a number of deliberate and disciplined actions. We have reduced supply, resisted selling into a weak spot market, restructured our global marketing organization, streamlined our operations and reduced costs. In 2017, these actions resulted in lower:

| • |  | capital expenditures

| • |  | direct administration costs

| • |  | exploration costs

| • |  | uranium average unit cost of sales

Consistent with these actions, we have reduced our planned 2018 annual dividend to $0.08 per share and it will be paid annually instead of quarterly. In addition, we are temporarily suspending production at our McArthur River/Key Lake operation, which we expect will remove 18 million pounds of uranium from the market in 2018. Although these actions will have a cost in the short-term, they are intended to position us to be able to self-manage the risks we face and ensure our tier-one assets are available to us in a market that values them appropriately.

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

In 2017, we made changes to the way our global marketing activities are organized. To better co-ordinate our marketing activities and reduce costs, all future Canadian and international marketing activities have been consolidated in Saskatoon. These changes have a significant impact on the activities historically performed by NUKEM. We will continue to be active in the spot market when it makes sense for us and in support of our long-term contract portfolio. However, our marketing activities will now largely be undertaken by our new marketing entity, Cameco Marketing Inc., based out of Saskatoon.

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

| • |  | allow us to execute on our dividend while ensuring it is appropriately aligned with the cyclical nature of our earnings

MANAGEMENT’S DISCUSSION AND ANALYSIS 13

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 capital allocation 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

With the metrics that inform an investment-grade rating in mind, and in this period of low uranium prices, we have taken steps to improve margin and cash flow by:

| • |  | responsibly managing our sources of supply and preserving the value of our tier-one assets

| • |  | restructuring our activities to reduce our operating, capital, and general and administrative spending

| • |  | reducing our planned annual dividend from $0.40 per share to $0.08 per share in 2018

REINVESTMENT

If a decision is made to reinvest capital 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 investment prospects internally or externally, this may result in residual investable capital, which we would then consider returning directly to shareholders.

Given the weak uranium market, our focus for 2018 through 2020 is primarily on sustaining and capacity replacement capital to ensure we have the ability to meet our contractual commitments and to maintain optionality longer term. All growth capital has been curtailed.

RETURN

We believe in returning cash to shareholders, but are also focused on protecting the company and rewarding those shareholders who understand and support our strategy to build long-term value. If we determine the best use of cash is to return it to shareholders, we can do that through a share repurchase or dividend—an annual dividend, one-time supplemental dividend or a progressive dividend. 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 few 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: The amount and type of dividend paid, annual, progressive or one-time supplemental is evaluated by our board of directors with careful consideration of our cash flow, financial position, strategy, and other relevant factors including appropriate alignment with the cyclical nature of our earnings.

14 CAMECO CORPORATION

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 accordance with market conditions, and to mitigate risk, we evaluate the optimal mix of our production, inventory and purchases in order to satisfy our contractual commitments and in order to return the best value possible. During a prolonged period of uncertainty, this could mean leaving our uranium in the ground.

In general, we are always active in the market, buying and selling uranium when it is beneficial for us and in support of our long-term contract portfolio. We undertake activity in the spot and term markets prudently, looking at the prices and other business factors to decide whether it is appropriate to purchase or sell into the spot or term market. Not only is this activity a source of profit, it gives us insight into underlying market fundamentals.

In particular, in 2018, in addition to our purchase commitments, we intend to be active buyers in the spot market. This activity may mean we give up some margin in the near-term, however, we believe it will provide us with the supply flexibility we need to meet our sales commitments and will allow us to preserve the value of our tier-one assets. Our goal is to protect and extend the value of our contract portfolio on terms that recognize the value of our assets and are consistent with our marketing strategy – providing adequate protection when prices go down and allow us to benefit when prices rise.

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 objectives of our contracting strategy are to:

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

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

| • |  | establish and grow market share with strategic customers

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 for uranium: are typically based on a term-price indicator at the time the contract is accepted and escalated over the term of the contract.

Market-related contracts for uranium: 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, which are usually 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 15

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.

CONTRACT PORTFOLIO STATUS

We have commitments to sell almost 150 million pounds of U3O8 with 39 customers worldwide in our uranium segment, and over 40 million kilograms as UF6 conversion with 31 customers worldwide in our fuel services segment. The annual average sales commitments over the next five years in our uranium segment is 22 million pounds, with commitment levels through 2020 higher than in 2021 and 2022.

Customers – U3O8:

Five largest customers account for 55% of commitments

COMMITTED U3O8 SALES BY REGION

Customers – UF6 conversion:

Five largest customers account for 59% 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 our JV Inkai agreement, under long-term agreements and in the spot market

| • |  | our existing inventory

16 CAMECO CORPORATION

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

| • |  | the level of sales commitments in our long-term contract portfolio

| • |  | 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.

2017 URANIUM OPERATING COSTS BY CATEGORY

Operating costs in our fuel services segment are mainly fixed. In 2017, labour accounted for about 56% of the total. The largest variable operating cost is for zirconium, followed by energy (natural gas and electricity), maintenance supplies, and anhydrous hydrogen fluoride.

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.

We believe the deliberate and disciplined actions we have taken to reduce supply, streamline operations and reduce costs will help shield the company from the nearer term risks we face and will reward shareholders for their continued patience and support of our strategy to build long-term value.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 17

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.

Sustainable development: A key part of our strategy, reflecting our values

Social responsibility, safety of our workforce and the public, as well as environmental protection are top priorities for us. In fact, 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. Sustainability is 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

Given this, we have sustainable development principles and practices embedded throughout our organization, from our overall corporate strategy to day-to-day operations.

Consequently, we recognize that changes in our operations and support functions, including the suspension of production at Rabbit Lake and curtailment at the US operations in 2016, the temporary suspension of production at our McArthur River/Key Lake operation in 2018, the reduction of the workforce at our northern Saskatchewan operations and at our corporate office, and the changes made to the way our global marketing activities are organized 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.

2017 Highlights:

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

| • |  | continued low average dose of radiation to workers, including the Cigar Lake operation as it increased production to licensed capacity

| • |  | Port Hope conversion facility, Cameco Fuel Manufacturing and Key Lake made significant improvements in their safety performance over 2016

| • |  | recognized for several top employer awards

| • |  | continued improvement of safety systems for support groups, such as exploration and corporate facilities

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 continually improve our performance.

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.

18 CAMECO CORPORATION

2017 Highlights:

| • |  | brought Cigar Lake up to full production without exceeding an environmental limit or having a significant environmental incident

| • |  | while readying to implement the new version of the ISO 14001 standard, added Cameco Fuel Manufacturing to our corporate ISO 14001 certification, which now encompasses all Cameco operations

| • |  | completed the multi-year implementation of an environmental monitoring database for all Cameco operations

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

| • |  | successfully managed an extended summer shutdown at Key Lake, McArthur River and Cigar Lake with no significant environmental incidents

| • |  | implemented new Canadian Standards Association (CSA) environmental standards at our Fuel Services Division facilities

| • |  | continued efforts to systematically improve energy conservation and efficiency in our Fuel Services and Saskatchewan facilities

| • |  | 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.

2017 Highlights:

| • |  | over $170 million in procurement from locally owned northern Saskatchewan companies (80% of total)

| • |  | 954 local personnel from northern Saskatchewan (603 Cameco employees, 351 contractors)

| • |  | signed a Collaboration Agreement with the Lac La Ronge Indian Band

| • |  | for the first time in three years, we held a northern leaders roundtable – featuring nearly 50 northern Saskatchewan leaders, discussing the current uranium market

OUTSTANDING FINANCIAL PERFORMANCE

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

2017 Highlights:

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

| • |  | ranked 32nd out of 242 Canadian companies by Globe and Mail in governance practices

Our governance practices

We believe that sound governance is the foundation for strong corporate performance. Our board of directors is responsible for overseeing management and our strategy and business affairs. Its goal is to ensure we operate as a successful business, optimizing financial returns while effectively managing risk.

In 2017, our board consisted of 11 directors who were selected based on their collective ability to contribute expertise to the broad range of issues the board faces when carrying out its responsibilities in overseeing our business and affairs.

WHAT WE DO:

| • |  | Independent board – nine of our ten directors (90%) are independent

| • |  | Non-executive chair leads the board – we maintain separate chair and CEO positions and have had a non-executive, independent chair of the board since 2003

| • |  | Share ownership – we require our directors and executives to own shares, or have an equity interest in Cameco to align their interests with those of our shareholders and share ownership is disclosed

| • |  | Majority voting for directors – the board adopted a majority voting policy in 2006

MANAGEMENT’S DISCUSSION AND ANALYSIS 19

| • |  | Strong risk oversight – the board and committees oversee our risk management program and strategic, financial and operational risks

| • |  | Formal assessment process – the directors assess the board, committees and individual directors’ performance

| • |  | Independent third-party review – the director assessment process is augmented by a third-party review every three years

| • |  | Serving on other boards – we limit the number of other public company boards our directors can serve on, and serve on together

| • |  | Director recruitment and board succession – we have term limits and a retirement policy for directors

| • |  | Diverse board – our board has a diverse mix of skills, background and experience and 30% of this year’s director nominees are female

| • |  | Independent advice – board committees have full authority to retain independent advisors to help them carry out their duties and responsibilities

| • |  | Code of conduct and ethics – directors, officers and employees must comply with our code of conduct and confirm their compliance every year

| • |  | Long-standing shareholder engagement – we communicate openly with shareholders and other stakeholders

| • |  | Say on pay – we have held an advisory vote on our approach to executive compensation every year since 2010

More information about our shareholder commitment, our governance principles, how our board operates and profiles of each of our directors can be found in our most recent management proxy circular and on our website at cameco.com/about/board-of-directors.

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 sustainability 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. We produced a data update in 2017, with one more coming in 2018. Our next full report is tentatively scheduled for 2019.

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, Canada’s Best Diversity Employers, and Canada’s Top Employers for Young People for 2017. We are a leading employer of indigenous peoples in Canada, and have procured nearly $3.6 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.

20 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.

2017 OBJECTIVES1 |  | TARGET |  | RESULTS |  |
OUTSTANDING FINANCIAL PERFORMANCE |  |
Earnings measure |  | Achieve targeted adjusted net earnings. |  | Did not achieve |  | •  adjusted net earnings was below the minimum target
Cash flow measure |  | Achieve cash flow from operations (after working capital changes). |  | Exceeded |  | •  cash flow from operations was above the target
SAFE, HEALTHY AND REWARDING WORKPLACE |  |
Workplace safety measure |  | 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. |  | Did not achieve |  | •  injury rates did not meet the planned reduction target for the year •  average radiation doses remained low and stable
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 2017
SUPPORTIVE COMMUNITIES |  |
Stakeholder support measure |  | 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

1 | Detailed results for our 2017 corporate objectives and the related targets will be provided in our 2018 management proxy circular prior to our Annual Meeting of Shareholders on May 16, 2018.

2018 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 |  | 2017 CONSOLIDATED FINANCIAL RESULTS
34 |  | OUTLOOK FOR 2018
36 |  | LIQUIDITY AND CAPITAL RESOURCES
41 |  | 2017 FINANCIAL RESULTS BY SEGMENT
41 |  | URANIUM
43 |  | FUEL SERVICES
43 |  | NUKEM
45 |  | FOURTH QUARTER FINANCIAL RESULTS
45 |  | CONSOLIDATED RESULTS
48 |  | URANIUM
50 |  | FUEL SERVICES
50 |  | NUKEM

22 CAMECO CORPORATION

2017 consolidated financial results

In this MD&A, our 2018 financial outlook and other disclosures relating to our contract portfolio are presented on a basis which excludes the agreement with TEPCO, which is under dispute. See Also of Note on page 7.

HIGHLIGHTS |  |  |  |  |  |  |  | CHANGE FROM |
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | 2016 TO 2017 |
Revenue |  |  | 2,157 |  |  |  | 2,431 |  |  |  | 2,754 |  |  |  | (11 | )%
Gross profit |  |  | 436 |  |  |  | 463 |  |  |  | 697 |  |  |  | (6 | )%
Net earnings (loss) attributable to equity holders |  |  | (205 | ) |  |  | (62 | ) |  |  | 65 |  |  |  | >100 | %
$ per common share (basic) |  |  | (0.52 | ) |  |  | (0.16 | ) |  |  | 0.16 |  |  |  | >100 | %
$ per common share (diluted) |  |  | (0.52 | ) |  |  | (0.16 | ) |  |  | 0.16 |  |  |  | >100 | %
Adjusted net earnings (non-IFRS, see page 24) |  |  | 59 |  |  |  | 143 |  |  |  | 344 |  |  |  | (59 | )%
$ per common share (adjusted and diluted) |  |  | 0.15 |  |  |  | 0.36 |  |  |  | 0.87 |  |  |  | (58 | )%
Cash provided by operations (after working capital changes) |  |  | 596 |  |  |  | 312 |  |  |  | 450 |  |  |  | 91 | %

Net earnings

Our net earnings normally trend with revenue, but, in recent years, have been significantly influenced by impairment charges due to the continued weakness in the uranium market.

The following table shows what contributed to the change in net earnings in 2017 compared to 2016 and 2015.

($ MILLIONS) |  | 2017 |  |  | 2016 |  |  | 2015 |
Net earnings (losses)—previous year |  |  | (62 | ) |  |  | 65 |  |  |  | 58 |
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 |  | Higher (lower) sales volume |  |  | 29 |  |  |  | (16 | ) |  |  | (27 | )
|  | Lower realized prices ($US) |  |  | (222 | ) |  |  | (129 | ) |  |  | (76 | )
|  | Foreign exchange impact on realized prices |  |  | (36 | ) |  |  | 30 |  |  |  | 245 |
|  | Lower (higher) costs |  |  | 180 |  |  |  | (49 | ) |  |  | (136 | )
|  | change – uranium |  |  | (49 | ) |  |  | (164 | ) |  |  | 6 |
Fuel services |  | Lower sales volume |  |  | (5 | ) |  |  | (4 | ) |  |  | (5 | )
|  | Higher realized prices ($Cdn) |  |  | 21 |  |  |  | 25 |  |  |  | 50 |
|  | Higher costs |  |  | (15 | ) |  |  | (19 | ) |  |  | (22 | )
|  | change – fuel services |  |  | 1 |  |  |  | 2 |  |  |  | 23 |
NUKEM |  | Gross profit |  |  | 14 |  |  |  | (70 | ) |  |  | 20 |
|  | change – NUKEM |  |  | 14 |  |  |  | (70 | ) |  |  | 20 |
Other changes |  |  |  |  |  |  |  |  |  |  |  |
Lower (higher) administration expenditures |  |  | 44 |  |  |  | (20 | ) |  |  | (10 | )
Lower (higher) impairment charges |  |  | 4 |  |  |  | (147 | ) |  |  | 112 |
Lower (higher) exploration expenditures |  |  | 13 |  |  |  | (2 | ) |  |  | 6 |
Change in Rabbit Lake reclamation provision |  |  | (34 | ) |  |  | 34 |  |  |  | — |
Lower (higher) loss on disposal of assets |  |  | 16 |  |  |  | (21 | ) |  |  | 43 |
Change in gains or losses on derivatives |  |  | 22 |  |  |  | 315 |  |  |  | (160 | )
Change in foreign exchange gains or losses |  |  | (17 | ) |  |  | (65 | ) |  |  | 24 |
Lower loss on equity-accounted investments |  |  | — |  |  |  | 1 |  |  |  | 16 |
Gain on customer contract settlements in 2016 |  |  | (59 | ) |  |  | 59 |  |  |  | — |
Contract termination fee (SFL) in 2014 |  |  | — |  |  |  | — |  |  |  | 18 |
Arbitration award in 2014 |  |  | — |  |  |  | — |  |  |  | (66 | )
Debenture redemption premium in 2014 |  |  | — |  |  |  | — |  |  |  | 12 |
Change in income tax recovery or expense |  |  | (91 | ) |  |  | (49 | ) |  |  | (32 | )
Other |  |  | (7 | ) |  |  | — |  |  |  | (5 | )
Net earnings (losses) – current year |  |  | (205 | ) |  |  | (62 | ) |  |  | 65 |

MANAGEMENT’S DISCUSSION AND ANALYSIS 23

Impairment charges

In the third quarter, in line with the other disciplined actions we have taken, we made changes to the way our global marketing activities are organized. The changes significantly impact the marketing activities historically performed by NUKEM. As a result, we recognized an impairment charge for the full carrying value of goodwill of $111 million. See note 9 for more information.

During the fourth quarter we announced our plan to temporarily suspend production at the McArthur River/Key Lake operation in 2018. As a result, we have re-evaluated the project to complete the new calciner at Key Lake, which was undertaken to allow for increased production. Given the production suspension, current market conditions, and that we have determined the existing calciner has sufficient capacity to reliably meet our ongoing production requirements, it has been determined that no further investment will be made to complete the project. As a result, we have recognized an impairment charge related to the new calciner of $55 million. See note 8 for more information.

Also during the fourth quarter, we recorded a $184 million write down of our US assets. Due to the continued weakening of the uranium market and the reduction in mineral reserves, we concluded that it was appropriate to recognize an impairment charge for these assets. 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 NUKEM purchase price inventory recovery, impairment charges, Rabbit Lake reclamation provision adjustment, 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 2017, 2016 and 2015.

($ MILLIONS) |  | 2017 |  |  | 2016 |  |  | 2015 |
Net earnings (loss) attributable to equity holders |  |  | (205 | ) |  |  | (62 | ) |  |  | 65 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | (108 | ) |  |  | (130 | ) |  |  | 166 |
NUKEM purchase price inventory recovery |  |  | — |  |  |  | (6 | ) |  |  | (3 | )
Impairment charges |  |  | 358 |  |  |  | 362 |  |  |  | 215 |
Rabbit Lake reclamation provision adjustment |  |  | — |  |  |  | (34 | ) |  |  | — |
Income taxes on adjustments |  |  | 14 |  |  |  | 13 |  |  |  | (99 | )
Adjusted net earnings |  |  | 59 |  |  |  | 143 |  |  |  | 344 |

24 CAMECO CORPORATION

The following table shows what contributed to the change in adjusted net earnings (non-IFRS measure, see above) in 2017 compared to the same period in 2016 and 2015.

($ MILLIONS) |  | 2017 |  |  | 2016 |  |  | 2015 |
Net earnings—previous year |  |  | 143 |  |  |  | 344 |  |  |  | 412 |
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 |  | Higher (lower) sales volume |  |  | 29 |  |  |  | (16 | ) |  |  | (27 | )
|  | Lower realized prices ($US) |  |  | (222 | ) |  |  | (129 | ) |  |  | (76 | )
|  | Foreign exchange impact on realized prices |  |  | (36 | ) |  |  | 30 |  |  |  | 245 |
|  | Lower (higher) costs |  |  | 180 |  |  |  | (49 | ) |  |  | (136 | )
|  | change – uranium |  |  | (49 | ) |  |  | (164 | ) |  |  | 6 |
Fuel services |  | Lower sales volume |  |  | (5 | ) |  |  | (4 | ) |  |  | (5 | )
|  | Higher realized prices ($Cdn) |  |  | 21 |  |  |  | 25 |  |  |  | 50 |
|  | Higher costs |  |  | (15 | ) |  |  | (19 | ) |  |  | (22 | )
|  | change – fuel services |  |  | 1 |  |  |  | 2 |  |  |  | 23 |
NUKEM |  | Gross profit |  |  | 20 |  |  |  | (72 | ) |  |  | 22 |
|  | change – NUKEM |  |  | 20 |  |  |  | (72 | ) |  |  | 22 |
Other changes |  |  |  |  |  |  |  |  |  |  |  |
Lower (higher) administration expenditures |  |  | 44 |  |  |  | (20 | ) |  |  | (10 | )
Lower (higher) exploration expenditures |  |  | 13 |  |  |  | (2 | ) |  |  | 6 |
Lower (higher) loss on disposal of assets |  |  | 16 |  |  |  | (21 | ) |  |  | 1 |
Change in gains or losses on derivatives |  |  | 44 |  |  |  | 19 |  |  |  | (40 | )
Change in foreign exchange gains or losses |  |  | (17 | ) |  |  | (65 | ) |  |  | 25 |
Lower loss on equity-accounted investments |  |  | — |  |  |  | — |  |  |  | 16 |
Gain on customer contract settlements in 2016 |  |  | (59 | ) |  |  | 59 |  |  |  | — |
Contract termination fee (SFL) in 2014 |  |  | — |  |  |  | — |  |  |  | 18 |
Arbitration award in 2014 |  |  | — |  |  |  | — |  |  |  | (66 | )
Debenture redemption premium in 2014 |  |  | — |  |  |  | — |  |  |  | 12 |
Change in income tax recovery or expense |  |  | (90 | ) |  |  | 63 |  |  |  | (76 | )
Other |  |  | (7 | ) |  |  | — |  |  |  | (5 | )
Net earnings—current year |  |  | 59 |  |  |  | 143 |  |  |  | 344 |

Average realized prices

|  |  |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | CHANGE FROM 2016 TO 2017 |
Uranium1 |  | $US/lb |  |  | 36.13 |  |  |  | 41.12 |  |  |  | 45.19 |  |  |  | (12 | )%
|  | $Cdn/lb |  |  | 46.80 |  |  |  | 54.46 |  |  |  | 57.58 |  |  |  | (14 | )%
Fuel services |  | $Cdn/kgU |  |  | 27.20 |  |  |  | 25.37 |  |  |  | 23.37 |  |  |  | 7 | %
NUKEM |  | $Cdn/lb |  |  | 32.25 |  |  |  | 47.90 |  |  |  | 48.82 |  |  |  | (33 | )%

1 | Average realized foreign exchange rate ($US/$Cdn): 2017 – 1.30, 2016 – 1.32 and 2015 – 1.27.

MANAGEMENT’S DISCUSSION AND ANALYSIS 25

Revenue

The following table shows what contributed to the change in revenue for 2017.

($ MILLIONS) |  |  |
Revenue – 2016 |  |  | 2,431 |
Uranium |  |  |  |
Higher sales volume |  |  | 114 |
Lower realized prices ($Cdn) |  |  | (258 | )
Change in intersegment sales |  |  | (4 | )
Fuel services |  |  |  |
Lower sales volume |  |  | (29 | )
Higher realized prices ($Cdn) |  |  | 21 |
Change in intersegment sales |  |  | 1 |
NUKEM |  |  |  |
Change in revenue |  |  | (70 | )
Change in intersegment sales |  |  | (49 | )
Revenue – 2017 |  |  | 2,157 |

See 2017 Financial results by segment on page 41 for more detailed discussion.

THREE-YEAR TREND

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.

In 2017, revenue decreased by 11% compared to 2016 due to a decrease in the uranium spot price, resulting in an overall lower average realized price. In addition, prices on fixed price contracts were lower. This was partially offset by an increase in sales volumes in our uranium segment.

Revenue Outlook for 2018

We expect consolidated revenue to decrease in 2018 (outlook of $1,800 million to $1,930 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 and an expected decrease in sales volumes from NUKEM due to the restructuring of our marketing activities. In addition to our purchase and sales commitments, we will be active buying and selling uranium in the spot market if it makes sense for us. If we make additional sales with deliveries in 2018, we would expect our revenue outlook to increase.

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 2018 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.

26 CAMECO CORPORATION

Corporate expenses

ADMINISTRATION

($ MILLIONS) |  | 2017 |  |  | 2016 |  |  | CHANGE |
Direct administration |  |  | 151 |  |  |  | 195 |  |  |  | (23 | )%
Stock-based compensation |  |  | 12 |  |  |  | 12 |  |  |  | — |
Total administration |  |  | 163 |  |  |  | 207 |  |  |  | (21 | )%

Direct administration costs in 2017 were $44 million lower than in 2016. The decrease was mainly due to higher costs in 2016 related to:

| • |  | one-time costs related to collaboration agreements

| • |  | charges related to the consolidation of office space

| • |  | legal costs as our CRA dispute progressed towards trial

| • |  | restructuring of our NUKEM segment

We recorded $12 million in stock-based compensation expenses in 2017 under our stock option, restricted share unit, deferred share unit, performance share unit and phantom stock option plans, the same as in 2016. See note 22 to the financial statements.

Administration outlook for 2018

We expect administration costs (not including stock-based compensation) to be between $120 million to $130 million, lower compared to 2017, due to the restructuring we completed in 2017, our continued actions to reduce costs and lower expected costs related to our CRA litigation.

EXPLORATION

Our 2017 exploration activities focused on Canada and Australia. Our spend decreased from $43 million in 2016 to $30 million in 2017.

Exploration outlook for 2018

We expect exploration expenses to be about $20 million in 2018 due to an overall decrease in activity on our regional exploration projects. The focus for 2018 will be on our core projects in Saskatchewan.

FINANCE COSTS

Finance costs were $111 million, largely unchanged from $112 million in 2016. See note 17 to the financial statements.

FINANCE INCOME

Finance income was $5 million compared to $4 million in 2016.

MANAGEMENT’S DISCUSSION AND ANALYSIS 27

GAINS AND LOSSES ON DERIVATIVES

In 2017, we recorded $56 million in gains on our derivatives compared to $34 million in 2016. The increase reflects more significant strengthening in the Canadian dollar compared to the US dollar in 2017 compared to 2016. See Foreign exchange on page 32 and note 24 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $3 million in 2017 compared to a recovery of $94 million in 2016. The decrease in recovery was primarily due to the change in the distribution of earnings between jurisdictions compared to 2016. See note 19 to the financial statements.

In 2017, we recorded losses of $54 million in Canada compared to losses of $464 million in 2016, while earnings in foreign jurisdictions decreased to a loss of $154 million from earnings of $310 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 $17 million in 2017 compared to a recovery of $107 million in 2016. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

($ MILLIONS) |  | 2017 |  |  | 2016 |
Pre-tax adjusted earnings1 |  |  |  |  |  |  |  |
Canada |  |  | (101 | ) |  |  | (504 | )
Foreign |  |  | 143 |  |  |  | 542 |
Total pre-tax adjusted earnings |  |  | 42 |  |  |  | 38 |
Adjusted income taxes1 |  |  |  |  |  |  |  |
Canada |  |  | (27 | ) |  |  | (128 | )
Foreign |  |  | 10 |  |  |  | 21 |
Adjusted income tax recovery |  |  | (17 | ) |  |  | (107 | )

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 IRS since the first quarter of 2015. We have now settled our IRS dispute related to the 2009 through 2012 tax years, and in the third quarter we paid $198,000 (US) comprised of $122,000 (US) taxes owing plus interest.

Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing dispute 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 entered into between arm’s-length parties at that time.

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 2011, transfer pricing penalties. Taxes of approximately $321 million for the 2003 – 2017 years have already been paid to date in a jurisdiction outside Canada, and we are considering our options under bilateral international tax treaties to limit double taxation of this income. There is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our CRA tax dispute are represented by the amounts claimed by CRA and are described below.

28 CAMECO CORPORATION

CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements. To date, we received notices of reassessment for our 2003 through 2011 tax returns. We have recorded a cumulative tax provision of $61 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 2017. 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 2011 in the amount of $371 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 remitted a net amount of $303 million in cash. In addition, we have provided $421 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 2014 |  |  | 1 |  |  |  | 22 |  |  |  | 36 |  |  |  | 59 |  |  |  | 59 |  |  |  | — |
2014 |  |  | 106 |  |  |  | 47 |  |  |  | — |  |  |  | 153 |  |  |  | 153 |  |  |  | — |
2015 |  |  | 202 |  |  |  | 71 |  |  |  | 79 |  |  |  | 352 |  |  |  | 20 |  |  |  | 332 |
2016 |  |  | 51 |  |  |  | 38 |  |  |  | 31 |  |  |  | 120 |  |  |  | 32 |  |  |  | 88 |
2017 |  |  | — |  |  |  | 1 |  |  |  | 39 |  |  |  | 40 |  |  |  | 39 |  |  |  | 1 |
Total |  |  | 360 |  |  |  | 179 |  |  |  | 185 |  |  |  | 724 |  |  |  | 303 |  |  |  | 421 |

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 $8.4 billion of additional income taxable in Canada for the years 2003 through 2017, which would result in a related tax expense of approximately $2.5 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2011. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.95 billion and $2.15 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 required to remit or otherwise provide security for 50% of the cash taxes and transfer pricing penalties (between $970 million and $1.07 billion), plus related interest and instalment penalties assessed, which would be material to us.

Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. 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 remitting cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. We believe we will 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 2017, and include the expected timing adjustment for the inability to use any loss carry-backs starting with the 2008 tax year. We plan to update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2017.

MANAGEMENT’S DISCUSSION AND ANALYSIS 29

$ MILLIONS |  | 2003-2017 |  |  | 2018-2019 |  |  | 2020-2023 |  |  | TOTAL |
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period |
Cash payments |  |  | 226 |  |  |  | 65 - 90 |  |  |  | 120 - 145 |  |  |  | 410 - 460 |
Secured by letters of credit |  |  | 319 |  |  |  | 10 - 35 |  |  |  | 230 - 255 |  |  |  | 560 - 610 |
Total paid1 |  |  | 545 |  |  |  | 75 - 125 |  |  |  | 350 - 400 |  |  |  | 970 - 1070 |

1 | These amounts do not include interest and instalment penalties, which totaled approximately $179 million to December 31, 2017.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $724 million already paid or otherwise secured to date.

We have spent a total of about $57 million disputing the CRA reassessments and presenting our appeal in Tax Court. This amount includes legal fees, expert witness fees, consultant fees, filing expenses, and other costs related to the case, from the time we started specifically tracking such costs in 2009, through 2017. The largest expenditures have been incurred in 2016 and 2017 during trial preparation and court proceedings. If the decision of the Tax Court is appealed, additional costs will be incurred.

The trial for the 2003, 2005 and 2006 tax years concluded on September 13, 2017 and we expect to receive a Tax Court decision within six to 18 months of that date. Once the decision is issued, the rules that apply to our case permit either party to appeal the Tax Court decision to the Federal Court of Appeal. The decision of the Federal Court of Appeal can be appealed to the Supreme Court of Canada, but only if the Supreme Court agrees to hear the appeal. An appeal of a Tax Court of Canada decision to the Federal Court of Appeal must be filed within 30 days after the issuance of a Tax Court decision (excluding the months of July and August). The request to appeal a decision of the Federal Court of Appeal to the Supreme Court of Canada must be made within 60 days of issuance of a Federal Court of Appeal decision.

In the event that either party appeals the Tax Court decision, we anticipate that it would take about two years from the date the Tax Court decision is issued to receive a decision from the Federal Court of Appeal. If a further appeal is pursued, it would likely take about two years from the date the Federal Court of Appeal decision is issued to receive a decision from the Supreme Court of Canada.

The total tax amount reassessed for the 2003, 2005 and 2006 tax years was $11 million, and we remitted 50% of such amount at the time the reassessments were issued. In certain circumstances, including where neither party pursues an appeal of the Tax Court decision, CRA would issue revised reassessments for the 2003, 2005 and 2006 tax years that comply with the Tax Court decision. Following those reassessments, the corresponding tax payments or refunds, as applicable, plus interest, would be made or received, as applicable, within a reasonable period. Where one or more appeals are pursued by either party, reassessments might not be issued until after the decision on the final appeal is received. If the Tax Court decision results in an aggregate tax amount in excess of what we have already remitted, and we pursue an appeal of that decision, we may be required to remit additional cash tax amounts not exceeding the remaining unpaid portion of the original $11 million (plus interest) while that appeal is underway. Where the Tax Court decision results in a refund of the remitted portion of the original $11 million (with interest), we may not receive that refund until and unless the Tax Court decision is confirmed after the final appeal.

Once the Tax Court has delivered a decision for the 2003, 2005 and 2006 tax years we will consider how the decision relates to other years in issue (being 2004 and years subsequent to 2006). While the decision would not be legally binding for any year other than the trial years, we expect the ultimate decision for the trial years to be an important factor in resolving the dispute for the other years in issue.

30 CAMECO CORPORATION

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

This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA 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 2017 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 2011) in addition to interest charges and instalment penalties

| • |  | we will be substantially successful in our dispute with CRA and the cumulative tax provision of $61 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

|  | Material risks that could cause actual results to differ materially

| • |  | CRA reassesses us for years 2012 through 2017 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 outcome of our dispute with CRA results 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 not related to transfer pricing

| • |  | we are unable to effectively eliminate all double taxation

Tax outlook for 2018

On an adjusted net earnings basis, we expect a tax recovery of $40 to $50 million in 2018 as care and maintenance costs at our McArthur River/Key Lake operation will decrease earnings in Canada.

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. Beginning in 2016, many of the existing intercompany purchase and sale arrangements in our portfolio expired, and were replaced with new intercompany arrangements which reflect current market conditions. In addition, we recently changed our global marketing organization. The existing purchase and sale arrangements will continue to be in place until they expire. As the existing contracts expire, we anticipate that more income will be earned in Canada.

In 2019, we expect our consolidated tax rate will transition to a modest expense, and then, trend toward the Canadian statutory rate in the longer term. 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.

During December 2017, United States (US) tax reform legislation was substantively enacted. This new legislation will not result in a significant impact on our financial statements as we derecognized the amounts related to our US deferred tax asset in 2015. At that time, it was determined that it was no longer probable that there would be sufficient taxable profit in the future against which the US operating losses and other tax deductions could be used. The change in legislation does however, significantly reduce the value of our unrecognized US deferred tax assets due to the US tax rate decrease. In addition, we have alternative minimum tax credits of US $4,073,479 that will be refunded between 2018 and 2021.

MANAGEMENT’S DISCUSSION AND ANALYSIS 31

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 is based on a 60-month period and permits us to hedge 35% to 100% of our expected net exposure in the first 12 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 of 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 2018, 2019 and 2020 and we will recognize the gains or losses in ANE in those periods.

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, 2017. You can use this information to estimate the expected gains or losses on derivatives for 2018 on an ANE basis. However, if we add contracts to the portfolio that are designated for use in 2018 or if there are changes in the US/Cdn exchange rates in the year, those expected gains or losses could change.

32 CAMECO CORPORATION

HEDGE PORTFOLIO SUMMARY

DECEMBER 31, 2017 ($ MILLIONS) |  |  |  |  | 2018 |  |  | AFTER 2018 |  |  | TOTAL |
US dollar forward contracts |  |  | ($ millions) |  |  |  | 390 |  |  |  | 195 |  |  |  | 585 |
Average contract rate 1 |  |  | (US/Cdn dollar) |  |  |  | 1.30 |  |  |  | 1.28 |  |  |  | 1.30 |
US dollar option contracts |  |  | ($ millions) |  |  |  | 150 |  |  |  | 185 |  |  |  | 335 |
Average contract rate range1 |  |  | (US/Cdn dollar) |  |  |  | 1.27 to 1.31 |  |  |  | 1.26 to 1.31 |  |  |  | 1.26 to 1.31 |
Total US dollar hedge contracts |  |  | ($ millions) |  |  |  | 540 |  |  |  | 380 |  |  |  | 920 |
Effective hedge rate range2 |  |  | (US/Cdn dollar) |  |  |  | 1.23 to 1.25 |  |  |  | 1.26 to 1.28 |  |  |  | 1.24 to 1.26 |
Hedge ratio3 |  |  |  |  |  |  | 55 | % |  |  | 10 | % |  |  | 19 | %

1 | The average contract rate is the weighted 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, 2017:

| • |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.25 (Cdn), down from $1.00 (US) for $1.34 (Cdn) at December 31, 2016. The exchange rate averaged $1.00 (US) for $1.30 (Cdn) over the year.

| • |  | The mark-to-market position on all foreign exchange contracts was a $34 million gain compared to a $25 million loss at December 31, 2016.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2017, 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 24 to the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 33

Outlook for 2018

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

Our outlook for 2018 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 2018 financial outlook is presented on the basis of equity accounting for our minority ownership interest in JV Inkai. Under equity accounting, our share of the profits earned by JV Inkai on the sale of its production will be included in “income from equity-accounted investees” on our consolidated statement of earnings. Our share of production will be purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures. Please see JV Inkai Planning for the future on page 67 and Capital spending on page 37 for more details.

In addition, the 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.

The changes made to the organization of our global marketing activities in 2017, consolidating of all future Canadian and international marketing activities in Saskatoon, had a significant impact on the activities historically performed by NUKEM. As a result, we will no longer provide outlook for NUKEM.

We do not provide an outlook for the items in the table that are marked with a dash.

See 2017 Financial results by segment on page 41 for details.

2018 FINANCIAL OUTLOOK

|  | CONSOLIDATED |  |  | URANIUM |  |  | FUEL SERVICES |
EXPECTED CONTRIBUTION TO GROSS PROFIT |  |  | 100 | % |  |  | 85 | % |  |  | 15 | %
Production (owned and operated properties) |  |  | — |  |  |  | 9.1 million lbs |  |  |  | 9 to 10 million kgU |
Purchases |  |  | — |  |  |  | 8 to 9 million lbs | 1 |  |  | — |
Sales/delivery volume2 |  |  | — |  |  |  | 32 to 33 million lbs | 3 |  |  | 11 to 12 million kgU |
Revenue 2 |  | $ | 1,800-1,930 million |  |  | $ | 1,460-1,550 million | 4 |  | $ | 280-310 |
Average realized price3 |  |  | — |  |  | $ | 46.30/lb | 4 |  |  | — |
Average unit cost of sales (including D&A) |  |  | — |  |  | $ | 38.00-40.00/lb | 5 |  | $ | 21.60-22.60/kgU |
Direct administration costs6 |  | $ | 120-130 million |  |  |  | — |  |  |  | — |
Exploration costs |  |  | — |  |  | $ | 20 million |  |  |  | — |
Expected loss on derivatives - ANE basis4 |  | $ | 0-10 million |  |  |  | — |  |  |  | — |
Tax recovery - ANE basis7 |  | $ | 40-50 million |  |  |  | — |  |  |  | — |
Capital expenditures |  | $ | 90 million |  |  |  | — |  |  |  | — |

1 | Based on the volumes we currently have commitments to acquire under contract in 2018. This includes our JV Inkai purchases.

2 | Our 2018 outlook for sales volume and revenue does not include sales between our uranium, fuel services and NUKEM segments.

3 | Based on the volumes we currently have commitments to deliver under contract in 2018.

4 | Based on a uranium spot price of $22.00 (US) per pound (the Ux spot price as of January 31, 2018), a long-term price indicator of $30.00 (US) per pound (the Ux long-term indicator on January 31, 2018) and an exchange rate of $1.00 (US) for $1.25 (Cdn).

5 | Based on the expected unit cost of sales for produced material and committed long-term purchases including our JV Inkai purchases. If we make discretionary purchases in 2018, then we expect the overall unit cost of sales may be affected.

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

7 | Our outlook for the tax recovery is based on adjusted net earnings and the other assumptions listed in the table. The outlook does not include our share of taxes on JV Inkai profits as the income from JV Inkai is net of taxes. If other assumptions change then the expected recovery may be affected.

34 CAMECO CORPORATION

We now expect sales volumes for 2018 to be between 32 and 33 million pounds (previously 28 to 30 million pounds). The increase in our expected deliveries is primarily due to optimization of our contract portfolio, where we have brought forward deliveries into 2018.

REVENUE, ADJUSTED NET EARNINGS, AND CASH FLOW SENSITIVITY ANALYSIS

|  |  |  | IMPACT ON: |
FOR 2018 ($ MILLIONS) |  | CHANGE |  | REVENUE |  |  | ANE |  |  | CASH FLOW |
Uranium spot and term price1 |  | $5(US)/lb increase |  |  | 54 |  |  |  | 32 |  |  |  | 42 |
|  | $5(US)/lb decrease |  |  | (53 | ) |  |  | (31 | ) |  |  | (41 | )
Value of Canadian dollar vs US dollar |  | One cent decrease in CAD |  |  | 14 |  |  |  | 4 |  |  |  | 4 |
|  | One cent increase in CAD |  |  | (14 | ) |  |  | (4 | ) |  |  | (4 | )

1 | Assuming change in both Ux spot price ($22.00 (US) per pound on January 31, 2018) and the Ux long-term price indicator ($30.00 (US) per pound on January 31, 2018).

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 December 31, 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 December 31, 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 |
2019 |  |  | 33 |  |  |  | 43 |  |  |  | 55 |  |  |  | 65 |  |  |  | 74 |  |  |  | 81 |  |  |  | 87 |
2020 |  |  | 31 |  |  |  | 41 |  |  |  | 55 |  |  |  | 64 |  |  |  | 73 |  |  |  | 81 |  |  |  | 87 |
2021 |  |  | 28 |  |  |  | 41 |  |  |  | 55 |  |  |  | 66 |  |  |  | 75 |  |  |  | 84 |  |  |  | 93 |
2022 |  |  | 27 |  |  |  | 41 |  |  |  | 56 |  |  |  | 66 |  |  |  | 76 |  |  |  | 85 |  |  |  | 95 |

The table illustrates the mix of long-term contracts in our December 31, 2017 portfolio, and is consistent with our marketing strategy. It has been updated to reflect contracts entered into up to December 31, 2017.

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.

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 22 million pounds per year, with commitment levels in 2018 through 2020 higher than in 2021 and 2022

| • |  | 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 35

Liquidity and capital resources

Our financial objective is to ensure we have the cash and debt capacity to fund our operating activities, investments and other financial obligations.

At the end of 2017, we had cash and short-term investments of $592 million, 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 continue to provide a solid revenue stream. Over the next five years, we have commitments to deliver an average of 22 million pounds per year, with commitments levels in 2018 through 2020 higher than in 2021 and 2022.

In the currently weak uranium price environment, our focus is on preserving the value of our tier-one assets and reducing our operating, capital and general and administrative spending. 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 deliberate cost reduction measures implemented over the past five years, the reduction in our 2018 dividend, and the temporary suspension of production at our McArthur River/Key Lake operation, we expect to generate significant cash flow in 2018. Therefore, we expect our cash balances and operating cash flows to meet our capital requirements during 2018, and will help position us to self-manage risk.

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

|  | 2017 |  |  | 2016 |
Cash position ($ millions) (cash and cash equivalents) |  |  | 592 |  |  |  | 320 |
Cash provided by operations ($ millions) (net cash flow generated by our operating activities after changes in working capital) |  |  | 596 |  |  |  | 312 |
Cash provided by operations/net debt (net debt is total consolidated debt, less cash position) |  |  | 66 | % |  |  | 27 | %
Net debt/total capitalization (total capitalization is net debt and equity) |  |  | 16 | % |  |  | 18 | %

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. We remain focused on maintaining our investment-grade credit rating.

Third-party ratings for our commercial paper and senior debt as of February 7, 2018:

SECURITY |  | DBRS |  |  | S&P |
Commercial paper |  |  | R-2 (high | ) |  |  | A-2 | 1
Senior unsecured debentures |  |  | BBB (high | ) |  |  | BBB | 1
Rating trend / rating outlook |  |  | Negative | 2 |  |  | Negative | 3

1 | On February 24, 2017, S&P lowered its long term corporate credit rating from BBB+ to BBB and commercial paper to A-2.

2 | On May 26, 2017, DBRS changed Cameco’s rating trend to negative from stable.

3 | On November 14, 2017, S&P changed Cameco’s rating outlook to negative from stable.

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.

36 CAMECO CORPORATION

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) |  | 2017 |  |  | 2016 |
Cash and cash equivalents at beginning of year |  |  | 320 |  |  |  | 459 |
Cash from operations |  |  | 596 |  |  |  | 312 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment and acquisitions |  |  | (114 | ) |  |  | (217 | )
Other investing activities |  |  | 21 |  |  |  | (1 | )
Financing activities |  |  |  |  |  |  |  |
Interest paid |  |  | (69 | ) |  |  | (71 | )
Dividends |  |  | (158 | ) |  |  | (158 | )
Exchange rate on changes on foreign currency cash balances |  |  | (4 | ) |  |  | (4 | )
Cash and cash equivalents at end of year |  |  | 592 |  |  |  | 320 |

CASH FROM OPERATIONS

Cash from operations was 91% higher than in 2016 due in part to a decrease in working capital requirements. This was a result of a decrease in inventory compared to an increase in 2016. Working capital required $156 million less in 2017. In addition, while we had lower gross profits in our operating segments, less cash was required by our hedge portfolio as derivative contracts matured and cost reduction measures resulted in a lower use of cash. Not including working capital requirements, our operating cash flows in the year were up $128 million. See note 21 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.

CAMECO’S SHARE ($ MILLIONS) |  | 2017 PLAN1 |  |  | 2017 ACTUAL |  |  | 2018 PLAN |
Sustaining capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 10 |  |  |  | 12 |  |  |  | 5 |
Cigar Lake |  |  | 10 |  |  |  | 10 |  |  |  | 20 |
US ISR |  |  | 5 |  |  |  | 3 |  |  |  | — |
Inkai |  |  | 10 |  |  |  | 8 |  |  |  | — |
Fuel services |  |  | 15 |  |  |  | 11 |  |  |  | 30 |
Other |  |  | 5 |  |  |  | 6 |  |  |  | — |
Total sustaining capital |  |  | 55 |  |  |  | 50 |  |  |  | 55 |
Capacity replacement capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 35 |  |  |  | 34 |  |  |  | — |
Cigar Lake |  |  | 35 |  |  |  | 30 |  |  |  | 35 |
Inkai |  |  | 15 |  |  |  | 12 |  |  |  | — |
Total capacity replacement capital |  |  | 85 |  |  |  | 76 |  |  |  | 35 |
Growth capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 10 |  |  |  | 10 |  |  |  | — |
Cigar Lake |  |  | 10 |  |  |  | 2 |  |  |  | — |
Inkai |  |  | — |  |  |  | 5 |  |  |  | — |
Total growth capital |  |  | 20 |  |  |  | 17 |  |  |  | — |
Total uranium & fuel services |  |  | 160 |  |  |  | 143 | 2 |  |  | 90 |
JV Inkai (our 40% share)3 |  |  | — |  |  |  | — |  |  |  | 24 |

1 | Capital spending outlook was updated to $175 million (from $190 million) in our second quarter MD&A and to $160 million (from $175 million) in our third quarter MD&A.

2 | Total uranium & fuel services capital spending does not include adjustments for revenue from sales of pre-commercial production from Inkai block 3.

3 | Our share of JV Inkai capital spending for the 2018 plan is shown separately on the basis of equity accounting for our minority ownership interest. JV Inkai cash flows are expected to cover capital expenditures in 2018.

MANAGEMENT’S DISCUSSION AND ANALYSIS 37

Outlook for investing activities

CAMECO’S SHARE ($ MILLIONS) |  | 2019 PLAN |  |  | 2020 PLAN |
Total uranium & fuel services |  |  | 100-150 |  |  |  | 100-150 |
Sustaining capital |  |  | 55-80 |  |  |  | 55-80 |
Capacity replacement capital |  |  | 45-70 |  |  |  | 45-70 |
Growth capital |  |  | — |  |  |  | — |

We expect total 2018 capital expenditures for uranium and fuel services to be about 37% lower than in 2017 mainly due to the temporary suspension of operations at McArthur River/Key Lake, and the removal of capital spend at JV Inkai which will now be reflected in our overall investment due to the change to equity accounting. Capital expenditures for JV Inkai are expected to be covered by JV Inkai cash flows in 2018.

Major sustaining and capacity replacement expenditures in 2018 include:

| • |  | Fuel Services – ramp up of work on our Vision in Motion project

| • |  | Cigar Lake – work to expand freezing capacity and freeze hole drilling

Our expectation of capital spend in 2019 has been reduced to between $100 million and $150 million (previously $200 million to $250 million) as a result of the operational changes that resulted in cost savings, and removal of JV Inkai capital.

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.

Long-term contractual obligations

DECEMBER 31 ($ MILLIONS) |  | 2018 |  |  | 2019 AND 2020 |  |  | 2021 AND 2022 |  |  | 2023 AND BEYOND |  |  | TOTAL |
Long-term debt |  |  | — |  |  |  | 500 |  |  |  | 400 |  |  |  | 600 |  |  |  | 1,500 |
Interest on long-term debt |  |  | 69 |  |  |  | 110 |  |  |  | 82 |  |  |  | 144 |  |  |  | 405 |
Provision for reclamation |  |  | 37 |  |  |  | 88 |  |  |  | 99 |  |  |  | 828 |  |  |  | 1,052 |
Provision for waste disposal |  |  | 2 |  |  |  | 2 |  |  |  | 4 |  |  |  | — |  |  |  | 8 |
Other liabilities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 75 |  |  |  | 75 |
Capital commitments |  |  | 23 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 23 |
Total |  |  | 131 |  |  |  | 700 |  |  |  | 585 |  |  |  | 1,647 |  |  |  | 3,063 |

We have contractual capital commitments of approximately $23 million at December 31, 2017. 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, 2021. 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. 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, 2017, there were no amounts outstanding under this facility.

| • |  | At December 31, 2017, 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.

38 CAMECO CORPORATION

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, 2017, we complied with all covenants, and we expect to continue to comply in 2018.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at the end of 2017:

| • |  | 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. The following table is based on our purchase commitments in our uranium, fuel services and NUKEM segments at December 31, 2017 but does not include purchases of our share of Inkai production. These commitments include a mix of fixed-price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of delivery. We will update this table as required in our MD&A to reflect material changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

DECEMBER 31, 2017 ($ MILLIONS) |  | 2018 |  |  | 2019 AND 2020 |  |  | 2021 AND 2022 |  |  | 2023 AND BEYOND |  |  | TOTAL |
Purchase commitments1 |  |  | 434 |  |  |  | 206 |  |  |  | 120 |  |  |  | 2 |  |  |  | 762 |

1 | Denominated in US dollars, converted to Canadian dollars at the rate of 1.25.

As of December 31, 2017, we had committed to $762 million (Cdn) for the following:

| • |  | approximately 19 million pounds of U3O8 equivalent from 2018 to 2024

| • |  | approximately 2 million kgU as UF6 in conversion services in 2018 and 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, 2017 our financial assurances totaled $1.5 billion unchanged from December 31, 2016.

MANAGEMENT’S DISCUSSION AND ANALYSIS 39

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, we enter into arrangements with third parties where receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. Upon the sale, we assign the rights to the accounts receivable to the financial institution without recourse. These arrangements require us to satisfy our 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 we record on delivery of the product to the customer.

BALANCE SHEET

DECEMBER 31, 2017 ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | 2017 |  |  | 2016 |  |  | 2015 |  |  | CHANGE 2016 TO 2017 |
Inventory |  |  | 950 |  |  |  | 1,288 |  |  |  | 1,285 |  |  |  | (26 | )%
Total assets |  |  | 7,779 |  |  |  | 8,249 |  |  |  | 8,795 |  |  |  | (6 | )%
Long-term financial liabilities |  |  | 2,448 |  |  |  | 2,459 |  |  |  | 2,500 |  |  |  | (0 | )%
Dividends per common share |  |  | 0.40 |  |  |  | 0.40 |  |  |  | 0.40 |  |  |  | — |

Total product inventories decreased by 26% to $950 million this year due to sales being higher than the quantities produced and purchased during the year. In 2017, total volume of product inventories for the uranium segment decreased by 6% while the average cost of inventory decreased by 11% due to the addition of low cost produced material. This was somewhat offset by material purchased during the year at rates higher than the average cost of inventory. At December 31, 2017, our average cost for uranium was $30.72 per pound, down from $34.69 per pound at December 31, 2016. As of December 31, 2017, we held an inventory of 26.7 million pounds of U3O8 equivalent in our uranium segment (excluding broken ore).

At the end of 2017, our total assets amounted to $7.8 billion, a decrease of $0.5 billion compared to 2016, primarily due to a decrease in property, plant and equipment due to asset impairments. In 2016, the total asset balance decreased by $0.5 billion compared to 2015, also due to asset impairments.

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 2017 or 2016.

40 CAMECO CORPORATION

2017 financial results by segment

Uranium

HIGHLIGHTS |  |  |  |  | 2017 |  |  | 2016 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  |  |  | 23.8 |  |  |  | 27.0 |  |  |  | (12 | )%
Sales volume (million lbs)1 |  |  |  |  |  |  | 33.6 |  |  |  | 31.5 |  |  |  | 7 | %
Average spot price |  | ($ | US/lb | ) |  |  | 21.78 |  |  |  | 25.64 |  |  |  | (15 | )%
Average long-term price |  | ($ | US/lb | ) |  |  | 31.92 |  |  |  | 39.00 |  |  |  | (18 | )%
Average realized price |  | ($ | US/lb | ) |  |  | 36.13 |  |  |  | 41.12 |  |  |  | (12 | )%
|  | ($ | Cdn/lb | ) |  |  | 46.80 |  |  |  | 54.46 |  |  |  | (14 | )%
Average unit cost of sales (including D&A) |  | ($ | Cdn/lb | ) |  |  | 35.04 |  |  |  | 40.39 |  |  |  | (13 | )%
Revenue ($ millions)1 |  |  |  |  |  |  | 1,574 |  |  |  | 1,718 |  |  |  | (8 | )%
Gross profit ($ millions) |  |  |  |  |  |  | 395 |  |  |  | 444 |  |  |  | (11 | )%
Gross profit (%) |  |  |  |  |  |  | 25 |  |  |  | 26 |  |  |  | (4 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (101,000 pounds in sales and revenue of $3.9 million in 2017, nil in 2016).

Production volumes in 2017 decreased by 12% compared to 2016. Planned lower production from Inkai and our US operations, a lack of production from the suspended Rabbit Lake operation, and lower production from McArthur River/Key Lake due to calciner issues that delayed the mill restart following the extended summer shutdown and an unplanned calciner outage in October were partially offset by higher production from Cigar Lake as a result of the scheduled rampup of the operation. See Uranium – production overview on page 55 for more information.

Uranium revenues this year were down 8% compared to 2016 due to a decrease of 14% in the Canadian dollar average realized price, partially offset by an increase in sales volumes of 7%. The spot price for uranium averaged $21.78 (US) per pound in 2017, a decline of 15% compared to the 2016 average price of $25.64 (US) per pound. In addition, overall prices were lower than the prior year as a result of lower prices under fixed price contracts.

Total cost of sales (including D&A) decreased by 7% ($1.18 billion compared to $1.27 billion in 2016) due to lower unit cost of sales partially offset by higher sales volumes. The lower unit cost of sales was mainly due to higher costs in 2016 at Rabbit Lake and our US operations associated with curtailing production and lower production costs this year as a result of the ramp-up of production at Cigar Lake, and the other measures we have taken to reduce costs. The cost of our purchases have decreased as well.

The net effect was a $49 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) |  | 2017 |  |  | 2016 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 15.11 |  |  |  | 17.01 |  |  |  | (11 | )%
Non-cash cost |  |  | 11.67 |  |  |  | 11.81 |  |  |  | (1 | )%
Total production cost |  |  | 26.78 |  |  |  | 28.82 |  |  |  | (7 | )%
Quantity produced (million lbs) |  |  | 23.8 |  |  |  | 27.0 |  |  |  | (12 | )%
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 37.19 |  |  |  | 49.33 |  |  |  | (25 | )%
Quantity purchased (million lbs) |  |  | 6.1 |  |  |  | 8.4 |  |  |  | (27 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 28.90 |  |  |  | 33.69 |  |  |  | (14 | )%
Quantities produced and purchased (million lbs) |  |  | 29.9 |  |  |  | 35.4 |  |  |  | (16 | )%

MANAGEMENT’S DISCUSSION AND ANALYSIS 41

The average cash cost of production was 11% lower in the year than in 2016. The change was primarily due to the rampup of lower cost production from Cigar Lake, and the impact of our actions in 2016 to curtail production from Rabbit Lake and our US operations, where production costs were higher.

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 $37.19 (Cdn), or $29.23 (US) per pound, compared to $36.21 (US) per pound in the same period in 2016.

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 2017 and 2016 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS) |  | 2017 |  |  | 2016 |
Cost of product sold |  |  | 910.7 |  |  |  | 993.0 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (66.6 | ) |  |  | (115.3 | )
Other selling costs |  |  | (7.5 | ) |  |  | (8.9 | )
Care and maintenance and severance costs |  |  | (38.3 | ) |  |  | (69.6 | )
Change in inventories |  |  | (211.8 | ) |  |  | 74.5 |
Cash operating costs (a) |  |  | 586.5 |  |  |  | 873.7 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 267.9 |  |  |  | 281.2 |
Change in inventories |  |  | 9.8 |  |  |  | 37.7 |
Total operating costs (b) |  |  | 864.2 |  |  |  | 1,192.6 |
Uranium produced & purchased (million lbs) (c) |  |  | 29.9 |  |  |  | 35.4 |
Cash costs per pound (a ÷ c) |  |  | 19.62 |  |  |  | 24.68 |
Total costs per pound (b ÷ c) |  |  | 28.90 |  |  |  | 33.69 |

URANIUM SEGMENT OUTLOOK

In November 2017 we announced our plan to temporarily suspend production at the McArthur River/Key Lake operation in 2018, and therefore, we expect to produce 9.1 million pounds in 2018. In addition, we have commitments under long-term contracts to purchase approximately 8 to 9 million pounds, including our purchases from JV Inkai. We anticipate an average purchase price of $34.70/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 32 and 33 million pounds of U3O8 in 2018. We expect the unit cost of sales to be higher than in 2017 (outlook between $38.00/lb to $40.00/lb), primarily due to increased costs for care and maintenance associated with the temporary suspension of production at our McArthur River/Key Lake operation. If we make additional discretionary purchases in 2018 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 2017 as a result of lower average realized price (outlook $1,460 million to $1,550 million).

42 CAMECO CORPORATION

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 $22.75/kg U3O8 ($10.26/lb) and a 15% royalty is charged on profit in excess of $22.75/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. 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 |  |  |  |  | 2017 |  |  | 2016 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  |  |  | 7.9 |  |  |  | 8.4 |  |  |  | (6 | )%
Sales volume (million kgU)1 |  |  |  |  |  |  | 11.5 |  |  |  | 12.7 |  |  |  | (9 | )%
Average realized price |  | ($ | Cdn/kgU | ) |  |  | 27.20 |  |  |  | 25.37 |  |  |  | 7 | %
Average unit cost of sales (including D&A) |  | ($ | Cdn/kgU | ) |  |  | 21.66 |  |  |  | 20.36 |  |  |  | 6 | %
Revenue ($ millions)1 |  |  |  |  |  |  | 313 |  |  |  | 321 |  |  |  | (2 | )%
Gross profit ($ millions) |  |  |  |  |  |  | 64 |  |  |  | 63 |  |  |  | 2 | %
Gross profit (%) |  |  |  |  |  |  | 20 |  |  |  | 20 |  |  |  | — |

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (60,000 kgU in sales and revenue of $0.3 million in 2017, 115,000 kgU in sales and revenue of $0.9 million in 2016).

Total revenue decreased by 2% due to a 9% decrease in sales volumes, partially offset by a 7% increase in the realized price.

The total cost of products and services sold (including D&A) decreased by 3% compared to 2016 to $249 million, as a 9% decrease in sales volumes was partially offset by a 6% increase in the average unit cost of sales (including D&A). When compared to 2016, the average unit cost of sales was 6% higher due to the mix of fuel services products sold.

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

FUEL SERVICES OUTLOOK

In 2018, we plan to produce 9 to 10 million kgU, and we expect sales volumes, not including intersegment sales, to be 11 to 12 million kgU. Overall revenue is expected to be lower than 2017 (outlook $280 million to $310 million) due to a lower anticipated 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

(financial results include U3O8, UF6, and SWU)

HIGHLIGHTS |  |  |  |  | 2017 |  |  | 2016 |  |  | CHANGE |
Sales volume U3O8 (million lbs)1 |  |  |  |  |  |  | 10.0 |  |  |  | 7.1 |  |  |  | 41 | %
Average realized price |  | ($ | Cdn/lb | ) |  |  | 32.25 |  |  |  | 47.90 |  |  |  | (33 | )%
Cost of product sold (including D&A) |  |  |  |  |  |  | 336 |  |  |  | 419 |  |  |  | (20 | )%
Revenue ($ millions)1 |  |  |  |  |  |  | 321 |  |  |  | 391 |  |  |  | (18 | )%
Gross profit (loss) ($ millions) |  |  |  |  |  |  | (15 | ) |  |  | (28 | ) |  |  | 46 | %
Gross profit (loss) (%) |  |  |  |  |  |  | (5 | ) |  |  | (7 | ) |  |  | 29 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (1.7 million pounds in sales and revenue of $49 million in 2017, 48,000 pounds in sales and revenue of $0.4 million in 2016).

MANAGEMENT’S DISCUSSION AND ANALYSIS 43

During 2017, NUKEM delivered 10.0 million pounds of uranium, an increase of 2.9 million pounds compared to the previous year due to planned inventory reductions after the restructuring of Cameco’s global marketing activities. Revenues from NUKEM amounted to $321 million. Despite higher sales volumes, revenue decreased by 18% compared to 2016 as a result of a decline in the average realized price in the oversupplied uranium market. Gross loss percentage was 5% for 2017, compared to 7% for 2016.

The net effect was a $13 million increase in gross profit. Included in the 2017 gross loss is a $9 million net write-down of inventory compared to an $18 million write-down in 2016.

NUKEM OUTLOOK

The changes made to the organization of our global marketing activities in 2017, consolidating of all future Canadian and international marketing activities in Saskatoon, had a significant impact on the activities historically performed by NUKEM. As a result, we will no longer provide outlook for NUKEM.

44 CAMECO CORPORATION

Fourth quarter financial results

Consolidated results

HIGHLIGHTS |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($ MILLIONS EXCEPT WHERE INDICATED) |  | 2017 |  |  | 2016 |  |  | CHANGE |
Revenue |  |  | 809 |  |  |  | 887 |  |  |  | (9 | )%
Gross profit |  |  | 237 |  |  |  | 157 |  |  |  | 51 | %
Net loss attributable to equity holders |  |  | (62 | ) |  |  | (144 | ) |  |  | 57 | %
$ per common share (basic) |  |  | (0.16 | ) |  |  | (0.36 | ) |  |  | 56 | %
$ per common share (diluted) |  |  | (0.16 | ) |  |  | (0.36 | ) |  |  | 56 | %
Adjusted net earnings (non-IFRS, see page 24) |  |  | 181 |  |  |  | 90 |  |  |  | >100 | %
$ per common share (adjusted and diluted) |  |  | 0.46 |  |  |  | 0.23 |  |  |  | 100 | %
Cash provided by operations (after working capital changes) |  |  | 320 |  |  |  | 255 |  |  |  | 25 | %

NET EARNINGS

The following table shows what contributed to the change in net earnings and adjusted net earnings (non-IFRS measure, see page 8) in the fourth quarter of 2017 compared to the same period in 2016.

($ MILLIONS) |  | IFRS |  |  | ADJUSTED |
Net earnings (losses) - 2016 |  |  | (144 | ) |  |  | 90 |
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 |  | Higher sales volume |  |  | 11 |  |  |  | 11 |
|  | Higher realized prices ($US) |  |  | 23 |  |  |  | 23 |
|  | Foreign exchange impact on realized prices |  |  | (29 | ) |  |  | (29 | )
|  | Lower costs |  |  | 68 |  |  |  | 68 |
|  | change – uranium |  |  | 73 |  |  |  | 73 |
Fuel services |  | Higher sales volume |  |  | 3 |  |  |  | 3 |
|  | Lower realized prices ($Cdn) |  |  | (13 | ) |  |  | (13 | )
|  | Lower costs |  |  | 13 |  |  |  | 13 |
|  | change – fuel services |  |  | 3 |  |  |  | 3 |
NUKEM |  | Gross profit |  |  | 2 |  |  |  | 2 |
|  | change – NUKEM |  |  | 2 |  |  |  | 2 |
Other changes |  |  |  |  |  |  |  |
Lower administration expenditures |  |  | 16 |  |  |  | 16 |
Higher impairment charges |  |  | (9 | ) |  |  | — |
Lower exploration expenditures |  |  | 1 |  |  |  | 1 |
Change in Rabbit Lake reclamation provision |  |  | (43 | ) |  |  | — |
Lower loss on disposal of assets |  |  | 13 |  |  |  | 13 |
Change in gains or losses on derivatives |  |  | 29 |  |  |  | 4 |
Change in foreign exchange gains or losses |  |  | (2 | ) |  |  | (2 | )
Change in income tax recovery or expense |  |  | 5 |  |  |  | (13 | )
Other |  |  | (6 | ) |  |  | (6 | )
Net earnings (losses) - 2017 |  |  | (62 | ) |  |  | 181 |

MANAGEMENT’S DISCUSSION AND ANALYSIS 45

ADJUSTED NET EARNINGS

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) |  | 2017 |  |  | 2016 |
Net loss attributable to equity holders |  |  | (62 | ) |  |  | (144 | )
Adjustments |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | (2 | ) |  |  | 23 |
Impairment charges |  |  | 247 |  |  |  | 238 |
Rabbit Lake reclamation provision adjustment |  |  | 15 |  |  |  | (28 | )
Income taxes on adjustments |  |  | (17 | ) |  |  | 1 |
Adjusted net earnings |  |  | 181 |  |  |  | 90 |

ADMINISTRATION

|  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($ MILLIONS) |  | 2017 |  |  | 2016 |  |  | CHANGE |
Direct administration |  |  | 36 |  |  |  | 49 |  |  |  | (27 | )%
Stock-based compensation |  |  | 3 |  |  |  | 6 |  |  |  | (50 | )%
Total administration |  |  | 39 |  |  |  | 55 |  |  |  | (29 | )%

Direct administration costs were $36 million in the quarter, $13 million lower than the same period last year due to higher legal costs in 2016 related to our CRA trial, as well as cost reduction actions which reduced administration costs in 2017. Stock-based compensation expenses were $3 million lower than the fourth quarter of 2016. See note 22 to the financial statements.

Quarterly trends

HIGHLIGHTS |  | 2017 |  |  | 2016 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 809 |  |  |  | 486 |  |  |  | 470 |  |  |  | 393 |  |  |  | 887 |  |  |  | 670 |  |  |  | 466 |  |  |  | 408 |
Net earnings (loss) attributable to equity holders |  |  | (62 | ) |  |  | (124 | ) |  |  | (2 | ) |  |  | (18 | ) |  |  | (144 | ) |  |  | 142 |  |  |  | (137 | ) |  |  | 78 |
$ per common share (basic) |  |  | (0.16 | ) |  |  | (0.31 | ) |  |  | (0.00 | ) |  |  | (0.05 | ) |  |  | (0.36 | ) |  |  | 0.36 |  |  |  | (0.35 | ) |  |  | 0.20 |
$ per common share (diluted) |  |  | (0.16 | ) |  |  | (0.31 | ) |  |  | (0.00 | ) |  |  | (0.05 | ) |  |  | (0.36 | ) |  |  | 0.36 |  |  |  | (0.35 | ) |  |  | 0.20 |
Adjusted net earnings (loss) (non-IFRS, see page 24) |  |  | 181 |  |  |  | (50 | ) |  |  | (44 | ) |  |  | (29 | ) |  |  | 90 |  |  |  | 118 |  |  |  | (57 | ) |  |  | (7 | )
$ per common share (adjusted and diluted) |  |  | 0.46 |  |  |  | (0.13 | ) |  |  | (0.11 | ) |  |  | (0.07 | ) |  |  | 0.23 |  |  |  | 0.30 |  |  |  | (0.14 | ) |  |  | (0.02 | )
Cash provided by (used in) operations (after working capital changes) |  |  | 320 |  |  |  | 154 |  |  |  | 130 |  |  |  | (8 | ) |  |  | 255 |  |  |  | 385 |  |  |  | (51 | ) |  |  | (277 | )

Key things to note:

| • |  | Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 78% of consolidated revenues in the fourth quarter of 2017 and 66% of consolidated revenues in the fourth quarter of 2016.

| • |  | 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.

46 CAMECO CORPORATION

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

HIGHLIGHTS |  | 2017 |  |  |  |  |  | 2016 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  |  |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Net earnings (loss) attributable to equity holders |  |  | (62 | ) |  |  | (124 | ) |  |  | (2 | ) |  |  | (18 | ) |  |  |  |  |  |  | (144 | ) |  |  | 142 |  |  |  | (137 | ) |  |  | 78 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives |  |  | (2 | ) |  |  | (40 | ) |  |  | (44 | ) |  |  | (22 | ) |  |  |  |  |  |  | 23 |  |  |  | (27 | ) |  |  | (10 | ) |  |  | (116 | )
NUKEM purchase price inventory recovery |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | — |  |  |  | — |  |  |  | (6 | ) |  |  | — |
Impairment charges |  |  | 247 |  |  |  | 111 |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | 238 |  |  |  | — |  |  |  | 124 |  |  |  | — |
Rabbit Lake reclamation provision adjustment |  |  | 15 |  |  |  | (9 | ) |  |  | (12 | ) |  |  | 6 |  |  |  |  |  |  |  | (28 | ) |  |  | (6 | ) |  |  | — |  |  |  | — |
Income taxes on adjustments |  |  | (17 | ) |  |  | 12 |  |  |  | 14 |  |  |  | 5 |  |  |  |  |  |  |  | 1 |  |  |  | 9 |  |  |  | (28 | ) |  |  | 31 |
Adjusted net earnings (losses) (non-IFRS, see page 24) |  |  | 181 |  |  |  | (50 | ) |  |  | (44 | ) |  |  | (29 | ) |  |  |  |  |  |  | 90 |  |  |  | 118 |  |  |  | (57 | ) |  |  | (7 | )

MANAGEMENT’S DISCUSSION AND ANALYSIS 47

Fourth quarter financial results by segment

Uranium

|  |  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  |  | 2017 |  |  | 2016 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  |  |  | 6.9 |  |  |  | 7.1 |  |  |  | (3 | )%
Sales volume (million lbs)1 |  |  |  |  |  |  | 12.6 |  |  |  | 11.7 |  |  |  | 8 | %
Average spot price |  | ($ | US/lb | ) |  |  | 22.32 |  |  |  | 19.00 |  |  |  | 17 | %
Average long-term price |  | ($ | US/lb | ) |  |  | 30.67 |  |  |  | 32.83 |  |  |  | (7 | )%
Average realized price |  | ($ | US/lb | ) |  |  | 39.44 |  |  |  | 38.04 |  |  |  | 4 | %
|  | ($ | Cdn/lb | ) |  |  | 50.04 |  |  |  | 50.51 |  |  |  | (1 | )%
Average unit cost of sales (including D&A) |  | ($ | Cdn/lb | ) |  |  | 32.91 |  |  |  | 38.29 |  |  |  | (14 | )%
Revenue ($ millions)1 |  |  |  |  |  |  | 631 |  |  |  | 589 |  |  |  | 7 | %
Gross profit ($ millions) |  |  |  |  |  |  | 216 |  |  |  | 143 |  |  |  | 51 | %
Gross profit (%) |  |  |  |  |  |  | 34 |  |  |  | 24 |  |  |  | 42 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (101,000 pounds in sales and revenue of $3.9 million in Q4 2017, nil in Q4 2016).

Production volumes this quarter were 3% lower compared to the fourth quarter of 2016, due to curtailment of production at the US operations, lower production at Inkai, and from McArthur River/Key Lake. See Uranium – production overview on page 55 for more information.

Uranium revenues were up 7% due primarily to an 8% increase in sales volumes, as average realized price remained relatively constant.

Total cost of sales (including D&A) decreased by 7% ($415 million compared to $447 million in 2016). This was the result of a 14% decrease in the average unit cost of sales partially offset by an 8% increase in sales volumes. The decrease in the average unit cost of sales compared to last year was mainly due to timing of royalty costs. Also, the rampup of production at Cigar Lake, and the other measures we have taken to reduce costs, have resulted in lower production costs this year. The cost of our purchases have decreased as well.

The net effect was a $73 million increase 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 |  |  |  |
($CDN/LB) |  | 2017 |  |  | 2016 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 13.28 |  |  |  | 15.00 |  |  |  | (11 | )%
Non-cash cost |  |  | 12.08 |  |  |  | 10.74 |  |  |  | 12 | %
Total production cost |  |  | 25.36 |  |  |  | 25.74 |  |  |  | (1 | )%
Quantity produced (million lbs) |  |  | 6.9 |  |  |  | 7.1 |  |  |  | (3 | )%
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 34.74 |  |  |  | 50.49 |  |  |  | (31 | )%
Quantity purchased (million lbs) |  |  | 3.1 |  |  |  | 2.2 |  |  |  | 41 | %
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 28.27 |  |  |  | 31.59 |  |  |  | (11 | )%
Quantities produced and purchased (million lbs) |  |  | 10.0 |  |  |  | 9.3 |  |  |  | 8 | %

The average cash cost of production was 11% lower for the quarter than in the comparable period in 2016.

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 $34.74 (Cdn) per pound, or $28.41 (US) per pound in US dollar terms, compared to $37.61 (US) per pound in the fourth quarter of 2016.

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 2017 and 2016.

CASH AND TOTAL COST PER POUND RECONCILIATION

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2017 |  |  | 2016 |
Cost of product sold |  |  | 319.2 |  |  |  | 338.4 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (20.4 | ) |  |  | (38.0 | )
Other selling costs |  |  | (1.8 | ) |  |  | (0.3 | )
Care and maintenance and severance costs |  |  | (9.5 | ) |  |  | (10.8 | )
Change in inventories |  |  | (88.2 | ) |  |  | (71.7 | )
Cash operating costs (a) |  |  | 199.3 |  |  |  | 217.6 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 95.8 |  |  |  | 108.1 |
Change in inventories |  |  | (12.4 | ) |  |  | (31.9 | )
Total operating costs (b) |  |  | 282.7 |  |  |  | 293.8 |
Uranium produced & purchased (million lbs) (c) |  |  | 10.0 |  |  |  | 9.3 |
Cash costs per pound (a ÷ c) |  |  | 19.93 |  |  |  | 23.40 |
Total costs per pound (b ÷ c) |  |  | 28.27 |  |  |  | 31.59 |

MANAGEMENT’S DISCUSSION AND ANALYSIS 49

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

|  |  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  |  | 2017 |  |  | 2016 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  |  |  | 2.5 |  |  |  | 1.9 |  |  |  | 32 | %
Sales volume (million kgU)1 |  |  |  |  |  |  | 4.6 |  |  |  | 4.0 |  |  |  | 15 | %
Average realized price |  | ($ | Cdn/kgU | ) |  |  | 23.13 |  |  |  | 26.03 |  |  |  | (11 | )%
Average unit cost of sales (including D&A) |  | ($ | Cdn/kgU | ) |  |  | 18.43 |  |  |  | 21.17 |  |  |  | (13 | )%
Revenue ($ millions)1 |  |  |  |  |  |  | 107 |  |  |  | 104 |  |  |  | 3 | %
Gross profit ($ millions) |  |  |  |  |  |  | 22 |  |  |  | 19 |  |  |  | 16 | %
Gross profit (%) |  |  |  |  |  |  | 21 |  |  |  | 18 |  |  |  | 17 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (60,000 kgU in sales and revenue of $0.3 million in Q4 2017, 115,000 kgU in sales and revenue of $0.9 million in Q4 2016).

Total revenue increased by 3% due to a 15% increase in sales volumes, partially offset by an 11% decrease in average realized price. The decrease in average realized price was due to the mix of products sold.

Despite the increase in sales volume, total cost of sales (including D&A) remained unchanged at $85 million compared to the fourth quarter of 2016 due to a decrease of 13% in the average unit cost of sales, primarily as a result of the mix of products sold.

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

NUKEM

(financial results include U3O8, UF6, and SWU)

|  |  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  |  | 2017 |  |  | 2016 |  |  | CHANGE |
Uranium sales (million lbs)1 |  |  |  |  |  |  | 4.0 |  |  |  | 3.1 |  |  |  | 29 | %
Average realized price |  | ($ | Cdn/lb | ) |  |  | 30.81 |  |  |  | 46.63 |  |  |  | (34 | )%
Cost of product sold (including D&A) |  |  |  |  |  |  | 122 |  |  |  | 195 |  |  |  | (37 | )%
Revenue ($ millions)1 |  |  |  |  |  |  | 124 |  |  |  | 194 |  |  |  | (36 | )%
Gross profit (loss) ($ millions) |  |  |  |  |  |  | 2 |  |  |  | (1 | ) |  |  | >100 | %
Gross profit (loss) (%) |  |  |  |  |  |  | 2 |  |  |  | (1 | ) |  |  | >100 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (1.7 million pounds in sales and revenue of $49.0 million in Q4 2017, 48,000 pounds in sales and revenue of $0.4 million in Q4 2016).

NUKEM delivered 4.0 million pounds of uranium, an increase of 0.9 million pounds compared to 2016. NUKEM revenues amounted to $124 million compared to $194 million in 2016 due to a lower average realized price, partially offset by the increase in uranium volumes delivered due to planned inventory reductions after the restructuring of our global marketing activities. In addition, sales of UF6 and SWU in the fourth quarter 2016 contributed to the higher revenues last year.

Gross profit percentage was 2% in the fourth quarter of 2017, compared to a gross loss of 1% in the fourth quarter of 2016.

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

50 CAMECO CORPORATION

Operations and projects

This section of our MD&A is an overview of the mining properties we operate or have an interest in, our curtailed operations and our projects, 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 – TIER-ONE OPERATIONS
56 |  | MCARTHUR RIVER MINE / KEY LAKE MILL
61 |  | CIGAR LAKE
65 |  | INKAI
68 |  | URANIUM – TIER-TWO CURTAILED OPERATIONS
68 |  | RABBIT LAKE
68 |  | SMITH RANCH-HIGHLAND
68 |  | CROW BUTTE
69 |  | URANIUM – PROJECTS UNDER EVALUATION
69 |  | MILLENNIUM
69 |  | YEELIRRIE
69 |  | KINTYRE
70 |  | URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
71 |  | FUEL SERVICES
71 |  | BLIND RIVER REFINERY
72 |  | PORT HOPE CONVERSION SERVICES
72 |  | CAMECO FUEL MANUFACTURING INC. (CFM)
73 |  | 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. Also under review is the Canadian Environmental Protection Act, 1996. 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 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 US administration.

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 and accept 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.

Currently, Cameco is in the process of preparing updates to all Saskatchewan operations’ Preliminary Decommissioning Plan (PDP) and Preliminary Decommissioning Cost Estimate (PDCE) documents in accordance with the five year timeline specified in the regulations. An update to the Port Hope Conversion Facility PDP was initiated in 2015 in support of the licence renewal and the PDP was finalized early in the first quarter of 2016. In February 2017, the CNSC granted a licence renewal for 10 years and accepted the updated PDP and financial assurance amount. The financial assurance was amended to $128.6 million in March 2017.

For both Cameco Fuel Manufacturing and the Blind River Refinery, the increase to the financial assurance of $1.5 million and $9.4 million, respectively was considered through a hearing in writing in October 2017 and accepted in November 2017. The financial assurance amendment was completed in December 2017.

In addition, surety costs have increased at our Smith-Ranch Highland site by approximately $32 million. The increase is largely due to an increase in groundwater restoration costs.

At the end of 2017, 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 2017 (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 2017. 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 2017, we invested:

| • |  | $63 million in environmental protection, monitoring and assessment programs, approximately 21% less than in 2016

| • |  | $23 million in health and safety programs, or 17% less than 2016

The decrease in spend in 2017 was largely due to overall cost reductions.

Spending on environmental and health and safety programs is expected to decrease in 2018 as a result of the continued impacts of the decisions to transition Rabbit Lake into care and maintenance and to curtail production at the US operations, as well as the temporary shutdown of the McArthur River and Key Lake operations.

MANAGEMENT’S DISCUSSION AND ANALYSIS 53

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

| • |  | 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.

54 CAMECO CORPORATION

Uranium – production overview

Production in our uranium segment in the fourth quarter was 6.9 million pounds, 3% lower compared to the same period in 2016 due to lower production at Inkai, and our McArthur River/Key Lake operation due to calciner issues. Production for the year was 23.8 million pounds, 12% lower than in 2016 due to the strategic decisions made to suspend production at Rabbit Lake, curtail production at the US operations, and lower production from McArthur River/Key Lake, partially offset by higher production at Cigar Lake as ramp up was completed. See Uranium—operations starting on page 56 for more information.

Uranium production

CAMECO SHARE |  | THREE MONTHS ENDED DECEMBER 31 |  |  | YEAR ENDED DECEMBER 31 |  |  |  |  |  |  |
(MILLION LBS) |  | 2017 |  |  | 2016 |  |  | 2017 |  |  | 2016 |  |  | 2017 PLAN1 |  |  | 2018 PLAN |
McArthur River/Key Lake |  |  | 3.5 |  |  |  | 3.8 |  |  |  | 11.2 |  |  |  | 12.6 |  |  |  | 11.5 |  |  |  | 0.1 |
Cigar Lake |  |  | 2.5 |  |  |  | 2.5 |  |  |  | 9.0 |  |  |  | 8.7 |  |  |  | 9.0 |  |  |  | 9.0 |
Inkai |  |  | 0.9 |  |  |  | 0.7 |  |  |  | 3.2 |  |  |  | 3.4 |  |  |  | 3.1 |  |  |  | — | 2
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1.1 |  |  |  | — |  |  |  | — | 3
Smith Ranch-Highland |  |  | — |  |  |  | 0.1 |  |  |  | 0.3 |  |  |  | 0.9 |  |  |  | 0.3 |  |  |  | — | 3
Crow Butte |  |  | — |  |  |  | — |  |  |  | 0.1 |  |  |  | 0.3 |  |  |  | 0.1 |  |  |  | — | 3
Total |  |  | 6.9 |  |  |  | 7.1 |  |  |  | 23.8 |  |  |  | 27.0 |  |  |  | 24.0 |  |  |  | 9.1 |

1 | We reduced our initial 2017 production plan to 24.0 million pounds (from 25.2 million pounds) due to reductions at McArthur River/Key Lake and Smith Ranch-Highland in the third quarter.

2 | We expect total production from Inkai to be 6.9 million pounds in 2018. Due to the transition to equity accounting, our share of production, 3.4 million pounds, will be shown as a purchase. Please see JV Inkai – planning for the future beginning on page 67 for more information.

3 | 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 – Tier-two 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 preserve the value of those assets and increase long-term shareholder value, and to do that with an emphasis on safety, people and the environment.

Given today’s weak market conditions and to mitigate risk, we plan to:

| • |  | ensure we continue to operate safely

| • |  | evaluate the optimal mix of production, inventory and purchases in order to retain the flexibility to deliver long-term value

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 55

Uranium – Tier-one operations

McArthur River mine / Key Lake mill

|  | 2017 Production (our share) 11.2M lbs 2018 Production Outlook (our share) 0.1M lbs Estimated Reserves (our share) 250.7M lbs Estimated Mine Life 2038 |  | Proportion of 2017 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.

In 2018, production at the mine and mill is temporarily suspended.

McArthur River is considered a material uranium property for us.

Location |  | Saskatchewan, Canada
Ownership |  | McArthur River – 69.805%
|  | Key Lake – 83.33%
Mine type |  | Underground
Mining methods |  | Primary: blasthole stoping
|  | Secondary: raiseboring
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 250.7 million pounds (proven and probable), average grade U3O8: 9.63%
Estimated resources |  | 4.9 million pounds (measured and indicated), average grade U3O8: 3.00%
|  | 5.9 million pounds (inferred), average grade U3O8: 5.01%
Licensed capacity |  | Mine and mill: 25.0 million pounds per year
Licence term |  | Through October, 2023
Total packaged production: 2000 to 2017 |  | 325.2 million pounds (McArthur River/Key Lake) (100% basis)
1983 to 2002 |  | 209.8 million pounds (Key Lake) (100% basis)
2017 production |  | 11.2 million pounds (16.1 million pounds on 100% basis)
2018 production outlook |  | 0.1 million pounds (0.2 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.

56 CAMECO CORPORATION

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.

Zone 4 is divided into three mining areas: north, central, and south. Prior to the production suspension, we were actively mining the lower central, and north areas. In the final quarter of 2017, we began mining in the upper central area following the successful completion of ground freezing and the first stages of development and construction. 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 freeze hole drilling is on hold for 2018 during the production suspension and will resume following the mine start-up. Following freeze hole drilling, outfitting and freezing will commence prior to production access drift development. Production from zone 1 is expected to begin in 2021.

We have successfully extracted over 325 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 seven mining areas with freeze walls and an eighth mining area is under development.

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. This mining method has been used extensively in the mining industry, including uranium mining. It involves:

| • |  | establishing drill access above the ore and extraction access 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

| • |  | expanding the circumference of the raise by drilling longholes around the raisebore hole and blasting the ore

| • |  | funneling the blasted material into the raisebore hole and dropping it to the extraction level below

| • |  | collecting the broken rock by line-of-sight remote-controlled scoop trams, and transporting it to the underground grinding circuit

| • |  | once the stope is mined out, backfilling it with concrete to maintain ground stability and allowing the next stope and/or raise to be mined

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 57

Boxhole mining was tested and approved for use at McArthur River. It is a higher-cost mining method that is not currently being used.

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

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

| • |  | the final slurry, at an average grade of 12% - 20% 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.

2017 UPDATE

Production

This year, in alignment with our efforts to reduce costs, our production plan included an extended summer shutdown during the third quarter. The shutdown, consisted of a four-week vacation period in July, followed by a two-week maintenance period at McArthur River and a four-week maintenance period at Key Lake. Production was expected to restart at the end of August, however, work on the calciner at Key Lake took longer than expected. Also, there was additional work required on the calciner in October, resulting in an unplanned outage at Key Lake. As a result, we lowered our 2017 production target to 11.5 million pounds (Cameco’s share) from 12.6 million pounds (Cameco’s share). Production from McArthur River/Key Lake for the year was 16.1 million pounds; our share was 11.2 million pounds. This was 11% lower than 2016 and 3% lower than our previous forecast for the year.

During the year, we reduced the workforce by about 10%, and made changes to the commuter flight services at the site. These measures were made to further reduce costs and improve efficiency at the operation.

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. During the fourth quarter we announced our plan to temporarily suspend production at the McArthur River/Key Lake operation in 2018. As a result, we have re-evaluated the project to complete the new calciner at Key Lake, which was undertaken to allow for increased production. Given the production suspension, current market conditions, and that we have determined the existing calciner has sufficient capacity to reliably meet our ongoing production requirements it has been determined that no further investment will be made to complete the project. As a result, we have recognized an impairment charge related to the new calciner of $55 million. See note 9 for more information.

New mining areas

We must bring on new mining zones to sustain production. The two new areas under active development included the upper central portion of zone 4 and zone 1. In the fourth quarter of 2017, sufficient development and construction was complete to enable initial production from the upper central part of zone 4.

58 CAMECO CORPORATION

In 2017, zone 1 freeze drilling was advanced from 48% to 90% completion. In addition, construction of the brine distribution piping system was advanced to approximately 20% completion. Remaining freeze drilling and brine distribution construction will be deferred until after mine restart.

In 2017, the south freeze plant construction and commissioning was completed followed by a 3 month operating period when chilled brine was supplied to zone 4. The plant has been since shut-down for the care and maintenance period and will be restarted when freezing of Zone 1 is ready to begin.

The mine life of McArthur River/Key Lake has been extended from 2037 to 2038 as a result of the planned temporary production suspension in 2018. See Mineral reserves and resources on page 74 for more information.

Exploration

In 2017, we continued with underground infill definition drilling of zone B in order to provide the information required for more detailed mining plans. Underground exploration drilling has been halted during the care and maintenance period.

PLANNING FOR THE FUTURE

Production

Due to continued uranium price weakness, and in accordance with our announcement at the end of 2017, we have temporarily suspended production. During January 2018, activities at the mine and mill were focused on putting the operation into a state of safe care and maintenance. As a result of the suspension, and the time required to restart the mine and mill, we do not expect the operation to produce any significant amount of uranium in 2018. The cost to maintain both operations during the suspension is expected to range between $6.5 million and $7.5 million per month.

Expansion potential

Once the market signals that new supply is needed and a decision is made to begin increasing annual production, we will undertake the work necessary to 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, including the extended summer shutdown, the workforce reduction, changes to the commuter flight services at the site, and the temporary suspension of production in 2018, 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 expired in December 2017, and the collective bargaining process has begun. There is a risk to the restart of operations after the production suspension 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 59

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.

60 CAMECO CORPORATION

Uranium – Tier-one operations

Cigar Lake |  |  |  |
|  | 2017 Production (our share) 9.0M lbs 2018 Production Outlook (our share) 9.0M lbs Estimated Reserves (our share) 99.0M lbs Estimated Mine Life 2028 |  | Proportion of 2017 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 Orano’s (previously AREVA) McClean Lake mill.

Cigar Lake is considered a material uranium property for us.

Location |  | Saskatchewan, Canada
Ownership |  | 50.025%
Mine type |  | Underground
Mining method |  | Jet boring system
End product |  | Uranium concentrate
Certification |  | ISO 14001 certified
Estimated reserves |  | 99.0 million pounds (proven and probable), average grade U3O8: 14.91%
Estimated resources |  | 49.1 million pounds (measured and indicated), average grade U3O8: 14.48%
| 11.8 million pounds (inferred), average grade U3O8: 5.97%
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 2017 |  | 46.9 million pounds (100% basis)
2017 production |  | 9.0 million pounds (18.0 million pounds on 100% basis)
2018 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 the 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).

MANAGEMENT’S DISCUSSION AND ANALYSIS 61

We continue development below the mineralization and we are currently mining in the eastern part of the ore body (referred to as Phase 1). Surface delineation drilling for the western portion (Phase 2) was completed in 2017.

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 18.0 million pounds. One JBS machine will be located below each frozen panel and the three JBS machines required are currently in operation. Two machines actively mine 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 15% U3O8, is pumped into transport truck containers and shipped to McClean Lake mill on a 69 kilometre all-weather road

62 CAMECO CORPORATION

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 Orano. Given the McClean Lake mill’s capacity, it is able to:

| • |  | operate at Cigar Lake’s targeted annual production level of 18.0 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. Orano’s McClean Lake mill is licensed to produce 24.0 million pounds annually.

2017 UPDATE

Production

Total packaged production from Cigar Lake was 18.0 million pounds U3O8; our share was 9.0 million pounds, achieving our forecast.

During the year, we:

| • |  | implemented an extended summer shutdown, reduced the workforce by about 10%, made changes to the shift rotation schedule, and made changes to the commuter flight services at the site. All of these measures were made to further reduce costs and improve efficiency at the operation.

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

| • |  | advanced the freeze plant expansion project through the pre-feasibility stage and commenced construction

Underground development

In 2017, we substantially completed 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

On June 29, the CNSC approved a 10-year renewal of the operating licence for Orano’s McClean Lake mill. The licence is valid until June 30, 2027.

Exploration

In 2017, we completed 16,571 metres of diamond drilling as part of the second year of a three-year 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 pre-feasibility study for Phase 2. Sufficient information has been obtained from the first two years of drilling to support completion of the pre-feasibility study.

PLANNING FOR THE FUTURE

Production

In 2018, 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 2018 production plan for the Cigar Lake mine includes an extended shutdown 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, preceded by a one- to two-week maintenance period with mine start-up planned before the end of the third quarter.

MANAGEMENT’S DISCUSSION AND ANALYSIS 63

In 2018, we expect to:

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

| • |  | transition to two new production crosscuts tunnels as per the mine plan, and backfill two crosscut tunnels where production is complete

MANAGING OUR RISKS

Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, chemical ore characteristics, performance of the water treatment system, 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, including the extended summer shutdown, the workforce reduction, changes to the shift rotation schedule, and changes to the commuter flight services at the site, which are intended to achieve cost savings and improve efficiency, carry with them increased risk of production disruption.

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.

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.

Environmental performance

The Cigar Lake orebody contains elements of concern with respect to the water quality and the receiving environment. The distribution of elements such as arsenic, molybdenum, selenium and others is non-uniform throughout the ore body, and this can result in complications in attaining effluent concentrations included in the licensing basis. Materialization of this risk could result in a potential deferral of production and additional capital and operating expenses required to modify the water treatment process to ensure environmental performance.

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 operation 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.

64 CAMECO CORPORATION

Uranium – Tier-one operations

Inkai

|  | 2017 Production (our share) 3.2M lbs 2018 Production Outlook (100% basis) 6.9 M lbs Estimated Reserves (our share) 107.8M lbs Estimated Mine Life 2045 (based on licence term) |  | Proportion of 2017 U production

Inkai is a very significant uranium deposit, located in Kazakhstan. The operator is JV Inkai limited liability partnership, which we jointly own (40%) with Kazatomprom (60%)1.

Inkai is considered a material uranium property for us.

Location |  | South Kazakhstan
Ownership |  | 40%1
Mine type |  | In situ recovery (ISR)
End product |  | Uranium concentrate
Certifications |  | BSI OHSAS 18001
|  | ISO 14001 certified
Estimated reserves |  | 107.8 million pounds (proven and probable), average grade U3O8: 0.03%
Estimated resources |  | 12.8 million pounds (measured and indicated), average grade U3O8: 0.03%
|  | 30 million pounds (inferred), average grade U3O8: 0.03%
Licensed capacity (wellfields) |  | 10.4 million pounds per year (our share 4.2 million pounds per year)1
Licence term |  | Through July 2045
Total packaged production: 2009 to 2017 |  | 42.3 million pounds (100% basis)
2017 production |  | 3.2 million pounds (5.5 million pounds on 100% basis)
2018 production outlook |  | 6.9 million pounds (100% basis)1
Estimated decommissioning cost (100% basis) |  | $11 million (US) (100% basis) (this estimate is currently under review)

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. Under the agreement, effective January 1, 2018, our ownership interest in the joint venture dropped to 40% and we will equity account for our investment. However, our share of production will gradually be reduced to 40% as JV Inkai increases production as provided for under the agreement. Due to the transition to equity accounting, our share of production will be shown as a purchase. See JV Inkai Restructuring Agreement for more information.

BACKGROUND

Mine description

The Inkai uranium deposit is a roll-front type orebody within permeable sandstones. The more porous and permeable units host several stacked and relatively continuous, sinuous “roll-fronts” of low-grade uranium forming a regional system. Superimposed over this regional system are several uranium projects and active mines.

Inkai’s mineralization ranges in depths from about 260 metres to 530 metres. The deposit has a surface projection of about 40 kilometres in length, and the width ranges from 40 to 1600 metres. The deposit has hydrogeological and mineralization conditions favorable for use of in-situ recovery (ISR) technology.

MANAGEMENT’S DISCUSSION AND ANALYSIS 65

Mining and milling method

JV Inkai uses conventional, well-established, and very efficient 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 2017 production from Inkai was 5.5 million pounds; our share was 3.2 million pounds, a decrease from 2016, in accordance with Kazatomproms’s planned 10% production decrease for 2017. The subsoil use law in Kazakhstan allows producers to produce within 20% (above or below) of their licensed capacity in a year.

Project funding

We have an outstanding loan for Inkai’s work on block 3 prior to the restructuring and, as of December 31, 2017, the principal and interest amounted to $117 million (US). Under the restructuring agreement, the partners have agreed that JV Inkai will distribute excess cash first as priority repayment of this loan. On January 12, 2018, a payment of $6 million (US) was received.

JV Inkai Restructuring Agreement

In 2016, we signed an agreement with our partner Kazatomprom and JV Inkai to restructure and enhance JV Inkai. The restructuring closed in December 2017 and took effect January 1, 2018. This restructuring was subject to obtaining all required government approvals including an amendment to JV Inkai’s Resource Use Contract, which were obtained. The restructuring consists of the following:

| • |  | JV Inkai has the right to produce 10.4 million pounds of U3O8 per year (our share 4.2 million pounds), an increase from the prior licensed annual production of 5.2 million pounds (our share 3.0 million pounds)

| • |  | JV Inkai has the right to produce until 2045 (previously, the licence terms, based on the boundaries prior to the restructuring, were to 2024 and 2030)

| • |  | our ownership interest in JV Inkai is 40% and Kazatomprom’s share is 60%. However, 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 are 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 share in all production will be 40%, matching our ownership interest.

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

| • |  | the boundaries of the mining area 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 the historically defined block 3 area provides for priority repayment

We along with Kazatomprom have also completed and reviewed a feasibility study for the purpose of evaluating the design, construction and operation of a uranium refinery in Kazakhstan. In accordance with the agreement, a decision has been made not to proceed with construction of the uranium refinery, as contemplated in the feasibility study. Kazatomprom has, pursuant to its option under the agreement, requested to licence our proprietary conversion technology for the purposes of investigating the feasibility of constructing and operating a UF6 conversion facility in Kazakhstan.

Our 2018 financial outlook is presented on the basis of equity accounting for our minority ownership interest in JV Inkai. Under equity accounting, our share of the profits earned by JV Inkai on the sale of its production will be included in “income from equity-accounted investees” on our consolidated statement of earnings. Our share of production will be purchased at a discount to the spot price and included at this value in inventory. In addition, JV Inkai capital is not included in our outlook for capital expenditures. Please see JV Inkai Planning for the future below for more details.

66 CAMECO CORPORATION

Block 3 exploration (prior to restructuring)

In 2017, Inkai completed the test leach on block 3, which resulted in drummed production of 207,065 pounds (not included in Inkai’s annual production). With the restructuring, a portion of block 3 was included in JV Inkai’s new mining area. JV Inkai has the right to mine this new area until mid-2045.

PLANNING FOR THE FUTURE

Production

We expect total production from Inkai to be 6.9 million pounds in 2018. Due to the transition to equity accounting, our share of production, 3.4 million pounds, will be shown as a purchase at a discount to the spot price and included in inventory at this value at the time of delivery. Our share of the profits earned by JV Inkai on the sale of its production will be included in “income from equity-accounted investees” on our consolidated statement of earnings.

MANAGING OUR RISKS

Political risk

Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our investment in JV Inkai is 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. The other owner of JV Inkai is Kazatomprom, an entity owned by the government of Kazakhstan. We have entered into agreements with JV Inkai and Kazatomprom intended to mitigate political risk. This risk includes the imposition of governmental laws or policies that could restrict or hinder JV Inkai repaying the block 3 loan, paying us dividends, or selling us our share of JV Inkai production, or that impose discriminatory taxes or currency controls on these transactions. The restructuring of JV Inkai, which took effect January 1, 2018, was undertaken with the objective to better align the interests of Cameco and Kazatomprom and includes a governance framework that provides for protection for us as a minority owner of JV Inkai. We believe the political risk related to our investment in JV Inkai is manageable.

For more details on this risk, please our most recent annual information form under the heading political risks.

JV Inkai manages risks listed on pages 52 to 54.

MANAGEMENT’S DISCUSSION AND ANALYSIS 67

Uranium – Tier-two 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. Due to market conditions, we suspended production at Rabbit Lake during the second quarter of 2016.

PRODUCTION AND PRODUCTION SUSPENSION

The facilities remained in a state of safe and sustainable care and maintenance throughout 2017. As a result, there was no production in 2017.

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

In 2016, as a result of the production suspension, we recognized an impairment charge for the full carrying value of $124 million.

US ISR Operations

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 67% lower than in 2016. At Crow Butte, 2017 production was 67% lower than in 2016. Production at both operations was lower due to the decision to curtail production in 2016.

The Nuclear Regulatory Commission licence renewal for Smith Ranch—Highland continues.

FUTURE PRODUCTION

As a result of our decision to defer all wellfield development at the US operations, production will cease in 2018, which is expected to result in production of less than 100,000 pounds.

IMPAIRMENT

During the fourth quarter, we recorded a $184 million write down of our US assets. Due to the continued weakening of the uranium market and the reduction in mineral reserves, we concluded that it was appropriate to recognize an impairment charge for these assets. See note 8 to the financial statements.

MANAGING OUR RISKS

We manage the risks listed on pages 52 to 54.

68 CAMECO CORPORATION

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.

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

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

The Kintyre deposit was discovered in 1985 and is amenable to open pit mining techniques.

2017 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 preserving the value of our tier-one uranium assets. We continue to await a signal from the market that additional production is needed prior to making any new development decisions.

PLANNING FOR THE FUTURE

2018 Planned activity

No work is planned at Millennium, Yeelirrie or Kintyre. 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 69

Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral reserves as they are depleted by our production, and is key to sustaining our business. However, during this period of weak uranium prices, and as we have ample idled production capacity, we have reduced our spending to focus only on exploration near our existing operations where we have established infrastructure and capacity to expand. In addition, we suspended our exploration in the Northern Territory, Australia. Globally, we have land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia and the US. Our land holdings total 1.0 million hectares (2.5 million acres). In northern Saskatchewan alone, we have direct interests in 640,000 hectares (1.6 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin.

2017 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 2017, we spent about $10 million on brownfields and projects under evaluation in Saskatchewan and Australia. At Inkai and the US operations we spent $2 million.

Regional exploration

We spent about $18 million on regional exploration programs (including support costs), primarily in Saskatchewan and, to a lesser extent, in Australia.

PLANNING FOR THE FUTURE

We will continue to focus on our core projects in Saskatchewan under our long-term exploration strategy. Long-term, we look 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.

ACQUISITION PROGRAM

Currently, given the conditions in the uranium market, our extensive portfolio of reserves and resources and our belief that we have ample idle production capacity, our focus is on maintaining our investment-grade rating and preserving the value of 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.

However, we continually evaluate acquisition opportunities within the nuclear fuel cycle that could add to our future supply options, 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. As such, 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.

70 CAMECO CORPORATION

Fuel services

Refining, conversion and fuel manufacturing

We control about 25% of world UF6 primary 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

MANAGEMENT’S DISCUSSION AND ANALYSIS 71

Port Hope Conversion Services

|  | Licensed Capacity 12.5M kgU of UF6 2.8M kgU of UO2 Licence renewal in Feb, 2027 |  |

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, 2027
Estimated decommissioning cost |  | $129 million

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

2017 UPDATE

Production

Fuel services produced 7.9 million kgU, 6% lower than 2016. 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)

In 2017, some early implementation aspects of the Vision in Motion project were completed and significant progress with detailed engineering was made. In 2018, detailed engineering will continue and substantial implementation activities will proceed.

Regulatory

The CNSC approved a 10-year operating licence which expires on February 28, 2027.

PLANNING FOR THE FUTURE

Production

We plan to production between 9 million and 10 million kgU in 2018.

MANAGING OUR RISKS

We manage the risks listed on pages 52 to 54.

72 CAMECO CORPORATION

NUKEM

Ownership |  | 100%
Activity |  | Trading of uranium and uranium-related products
2017 sales |  | 7.1 million pounds U3O8

BACKGROUND

In 2013, we acquired NUKEM, one of the world’s leading traders of uranium and uranium-related products.

In line with the other disciplined actions we have taken, in 2017, we made changes to the way our global marketing activities are organized. All future Canadian and international marketing activities will be consolidated in Saskatoon. These changes significantly impact the marketing activities historically performed by NUKEM. As a result, in the third quarter, we recognized an impairment charge for the full carrying value of the goodwill of $111 million.

We will continue to be active in the spot market when it makes sense for us and in support of our long-term contract portfolio. However, these activities will now largely be undertaken by our new marketing entity, Cameco Marketing Inc., based in Saskatoon.

MANAGEMENT’S DISCUSSION AND ANALYSIS 73

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 the 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. Mineral reserves and resources are all reported as of December 31, 2017 except for Inkai which for accounting purposes are reported as of January 1, 2018. Totals reported as of the end of 2017 are identical to those as of January 1, 2018.

We estimate and disclose mineral reserves and resources in five categories, using the definition standards adopted by the Canadian Institute of Mining, Metallurgy and Petroleum Council, 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 to demonstrate 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. 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 patterns. 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 with a high degree of confidence

| • |  | 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 with a degree of confidence lower than that applying to proven reserves

We use current geological models, average uranium prices of $44 to $54 (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.

74 CAMECO CORPORATION

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

(SHOWING CHANGE FROM 2016)

at December 31, 2017

Changes this year

Our share of proven and probable mineral reserves increased from 415 million pounds U3O8 at the end of 2016, to 458 million pounds at the end of 2017. The change was primarily the result of:

| • |  | JV Inkai’s amended Resource Use Contract which extended the mine life, increased the annual production level, changed our percent ownership and changed the boundaries of the mining area. This resulted in increases of 40 million pounds in proven mineral reserves, and 25 million pounds in probable mineral reserves.

partially offset by:

| • |  | production, which removed 24.5 million pounds from our mineral inventory

Measured and indicated mineral resources decreased from 487 million pounds U3O8 at the end of 2016, to 425 million pounds at the end of 2017. Our share of inferred mineral resources is 190 million pounds U3O8, a decrease of 58 million pounds from the end of 2016. The variance in mineral resources was mainly the result of:

| • |  | JV Inkai’s amended Resource Use Contract, which resulted in decreases of 23 million pounds and 45 million pounds in measured and indicated resources respectively, and a decrease of 56 million pounds in inferred resources

partially offset by:

| • |  | surface delineation drilling at Cigar Lake Phase 2 which added 7 million pounds to indicated resources

| • |  | transfer of nearly 2 million pounds to resources from reserves for the US ISR 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, manager, operations, McArthur River, Cameco

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

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

CIGAR LAKE

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

| • |  | Jeremy Breker, general manager, Rabbit Lake/Cigar Lake, Cameco

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

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

INKAI

| • |  | Darryl Clark, president, Cameco Kazakhstan LLP

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

| • |  | Bryan Soliz, principal geologist, Cameco Resources

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 75

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 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.

76 CAMECO CORPORATION

Mineral reserves

As at December 31, 2017, except for Inkai which are as at January 1, 2018 (100% – only the shaded column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

|  |  |  |  | PROVEN |  |  | PROBABLE |  |  | TOTAL MINERAL RESERVES |  |  | OUR SHARE RESERVES CONTENT (LBS U3O8) |  |  |  |
PROPERTY |  | MINING METHOD |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  |  | METALLURGICAL RECOVERY (%) |
Cigar Lake |  |  | UG |  |  |  | 215.6 |  |  |  | 16.88 |  |  |  | 80.2 |  |  |  | 386.6 |  |  |  | 13.81 |  |  |  | 117.7 |  |  |  | 602.1 |  |  |  | 14.91 |  |  |  | 197.9 |  |  |  | 99.0 |  |  |  | 99 |
Key Lake |  |  | OP |  |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 92 |
McArthur River |  |  | UG |  |  |  | 1,097.5 |  |  |  | 9.90 |  |  |  | 239.5 |  |  |  | 593.3 |  |  |  | 9.15 |  |  |  | 119.6 |  |  |  | 1,690.7 |  |  |  | 9.63 |  |  |  | 359.1 |  |  |  | 250.7 |  |  |  | 92 |
Inkai |  |  | ISR |  |  |  | 214,104.1 |  |  |  | 0.04 |  |  |  | 167.5 |  |  |  | 166,913.0 |  |  |  | 0.03 |  |  |  | 102.1 |  |  |  | 381,017.2 |  |  |  | 0.03 |  |  |  | 269.7 |  |  |  | 107.8 |  |  |  | 85 |
Total |  |  |  |  |  |  | 215,478.3 |  |  |  | — |  |  |  | 487.9 |  |  |  | 167,892.9 |  |  |  | — |  |  |  | 339.5 |  |  |  | 383,371.2 |  |  |  | — |  |  |  | 827.4 |  |  |  | 458.2 |  |  |  | — |

(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 per property, from $44 to $54 (US) per pound U3O8

| • |  | are based on exchange rates of $1.00 US=$1.25 Cdn and 265 Kazakhstan Tenge to $1.00 Cdn

Our estimate of mineral reserves and mineral resources may be positively or negatively affected by the occurrence of one or more of 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—operations 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 the 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 77

Mineral resources

As at December 31, 2017, except for Inkai which are as at January 1, 2018 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

|  | MEASURED RESOURCES (M) |  |  | INDICATED RESOURCES (I) |  |  |  |  |  | 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) |  |  | TOTAL M+I CONTENT (LBS U3O8) |  |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |
Cigar Lake |  |  | 8.7 |  |  |  | 7.35 |  |  |  | 1.4 |  |  |  | 298.8 |  |  |  | 14.69 |  |  |  | 96.8 |  |  |  | 98.2 |  |  |  | 49.1 |  |  |  | 180.0 |  |  |  | 5.97 |  |  |  | 23.7 |  |  |  | 11.8 |
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 |  |  | 89.8 |  |  |  | 2.71 |  |  |  | 5.4 |  |  |  | 15.6 |  |  |  | 4.70 |  |  |  | 1.6 |  |  |  | 7.0 |  |  |  | 4.9 |  |  |  | 76.8 |  |  |  | 5.01 |  |  |  | 8.5 |  |  |  | 5.9 |
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 |  |  |  | 18.7 |  |  |  | 842.5 |  |  |  | 2.38 |  |  |  | 44.1 |  |  |  | 11.8 |
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,836.5 |  |  |  | 0.95 |  |  |  | 38.6 |  |  |  | 38.6 |  |  |  | 38.6 |  |  |  | 2,460.9 |  |  |  | 0.62 |  |  |  | 33.7 |  |  |  | 33.7 |
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 |  |  | 1,779.4 |  |  |  | 0.18 |  |  |  | 6.9 |  |  |  | 1,354.9 |  |  |  | 0.29 |  |  |  | 8.6 |  |  |  | 15.5 |  |  |  | 15.5 |  |  |  | 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 |  |  | 36,680.9 |  |  |  | 0.03 |  |  |  | 21.3 |  |  |  | 21,132.2 |  |  |  | 0.02 |  |  |  | 10.7 |  |  |  | 32.0 |  |  |  | 12.8 |  |  |  | 116,394.6 |  |  |  | 0.03 |  |  |  | 75.0 |  |  |  | 30.0 |
North Butte-Brown Ranch |  |  | 910.1 |  |  |  | 0.08 |  |  |  | 1.7 |  |  |  | 5,530.3 |  |  |  | 0.07 |  |  |  | 8.4 |  |  |  | 10.0 |  |  |  | 10.0 |  |  |  | 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 |  |  | 3,721.3 |  |  |  | 0.10 |  |  |  | 7.9 |  |  |  | 14,372.3 |  |  |  | 0.05 |  |  |  | 17.0 |  |  |  | 24.9 |  |  |  | 24.9 |  |  |  | 6,861.0 |  |  |  | 0.05 |  |  |  | 7.7 |  |  |  | 7.7 |
Total |  |  | 71,139.6 |  |  |  | — |  |  |  | 142.5 |  |  |  | 69,889.1 |  |  |  | — |  |  |  | 451.2 |  |  |  | 593.7 |  |  |  | 425.3 |  |  |  | 133,479.0 |  |  |  | — |  |  |  | 307.5 |  |  |  | 189.9 |

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

78 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 14 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 79

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, 2017, 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, 2017. We have not made any change to our internal control over financial reporting during the 2017 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, 2017, and have not been applied in preparing these consolidated financial statements. We do 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 International Accounting Standards Board (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. Our assessment primarily involved reviewing our sales contracts to determine if any performance obligations exist that will need to be separately identified that may affect the timing of when revenue will be recognized under IFRS 15. Based on our assessment, we have not identified any material impacts on the timing and measurement of revenue from our existing revenue recognition practices from the adoption of the new standard, however we do expect to have additional disclosures.

80 CAMECO CORPORATION

IFRS 9, Financial Instruments (IFRS 9) – In July 2014, the IASB issued IFRS 9 which 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. We do not apply hedge accounting and do not currently intend to apply hedge accounting upon adoption of IFRS 9. Based on our assessment, we do not expect adoption of the standard to have a material impact on the financial statements, however we do expect to have additional disclosures.

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.

IFRIC 23, Uncertainty over Income Tax Treatments (IFRIC 23) – In June 2017, the IASB issued IFRIC 23 which is effective for periods beginning on or after January 1, 2019 with early adoption permitted. IFRIC 23 provides guidance on the accounting for current and deferred tax liabilities and assets in circumstances in which there is uncertainty over income tax treatments. The extent of the impact of the adoption of IFRIC 23 has not yet been determine.

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