Cenovus Energy
Annual Report 2017

Plain-text annual report

2017 ANNUAL REPORT Innovative well pad design – We’ve implemented a sleek new well pad design at our oil sands operations that requires less infrastructure. The new well pads, like this one at Christina Lake, start with the most basic equipment required for safe and reliable operation and have the ability to add infrastructure as required throughout the different phases of the pad lifecycle. This new design significantly reduces both the cost and environmental footprint of our well pads. Longer well lengths – At our oil sands operations, we’re successfully drilling longer horizontal wells. For example, we’ve drilled wells of up to 1,600 metres, double our average oil sands well length just a few years ago. We’ve also been improving the consistency of production along the full length of the well, which is known as conformance. With longer wells and better conformance, we’re able to produce the same amount of oil from fewer well pads, which helps to reduce both our environmental footprint and our costs. ON THE COVER TABLE OF CONTENTS At Cenovus, we have two core operating areas – our oil sands assets in northern Alberta where we use a technique called steam-assisted gravity drainage (SAGD), and our Deep Basin assets in Alberta and British Columbia where we have predominantly liquids-rich natural gas production. The top photo on the cover shows steam generators at our Christina Lake oil sands operations. The bottom photo shows one of our natural gas plants located in the Deep Basin near Edson, Alberta. 1 2 4 5 VISION, MISSION AND VALUES MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER MESSAGE FROM OUR BOARD CHAIR MANAGEMENT’S DISCUSSION AND ANALYSIS 64 CONSOLIDATED FINANCIAL STATEMENTS 73 117 121 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SUPPLEMENTAL INFORMATION ADVISORY 133 INFORMATION FOR SHAREHOLDERS For additional information about forward-looking statements, non-GAAP measures and reserves contained in this annual report, see our advisories on pages 5 and 121. Oil sands operations – The oil in our oil sands reservoirs is imbedded in tonnes of sand deep underground and can be as hard as a hockey puck. To be recovered, the oil needs to be heated and liquefi ed inside the reservoir using steam-assisted gravity drainage (SAGD). This is our Christina Lake oil sands project where we’re currently building our 50,000 barrels-per-day phase G expansion. First oil from phase G is anticipated in the second half of 2019 and is expected to increase production capacity at Christina Lake to 260,000 barrels per day. OUR VISION OUR VALUES To be the energy company of choice for investors, staff and stakeholders. Safety Safety before all else. OUR MISSION To maximize the value of the company by responsibly developing oil and natural gas assets in a safe, innovative and effi cient way. Integrity We are transparent, honest and treat everyone with respect. Performance We work as one team to make smart decisions that deliver results. Accountability We do what we say we will do. 2017 ANNUAL REPORT | 1 M E S S A G E F R O M O U R PRESIDENT & CHIEF EXECUTIVE OFFICER This is a pivotal time for Cenovus. In 2017, we went through a period of significant transition and change, largely driven by the acquisition of most of ConocoPhillips’ operations in Western Canada. At closing, the acquisition nearly doubled our production and reserves, gave us full ownership and control of our best-in-class oil sands assets and added a new high-quality core production area in the Deep Basin. As a result, I believe we have an extraordinary runway of opportunities for organic growth and long-term cash flow generation. At the same time, investor concerns about the acquisition, volatile commodity prices and a number of other factors contributed to a more than 40 percent decline in the value of our share price last year which was disappointing for all of us. When I joined Cenovus in November, I met directly with many of our investors, and I heard loud and clear that we must be more focused on creating shareholder value. While the acquisition gave us an enviable portfolio of assets, and Cenovus continues to deliver solid operational performance, our financial results have consistently lagged our peers in a number of important areas, including operating netbacks, cash flow growth and total shareholder return. We need to do some things differently, and I want to assure you that the process of change is already well underway. As Chief Executive Officer, my first order of business has been to continue executing on Cenovus’s plan to deleverage its balance sheet, and I’m extremely pleased with the progress we’ve made to date. In 2017, we announced sale agreements for our legacy conventional assets within our expected timeframe, further streamlining our portfolio and receiving excellent value for the assets in a challenging market. As promised, we applied the sales proceeds against our $3.6 billion bridge credit facility which was repaid and retired prior to the end of 2017. While paying down debt will continue to be a priority in 2018, this will not be a year of maintaining the status quo. I came to Cenovus with a mandate of change, and I’ve already taken steps to further contain spending and simplify our organization. For example, we’ve kept our 2018 capital budget capped at 2017 levels and suspended non-essential work on longer-term growth projects. I’ve also asked our teams to accelerate efforts to further reduce our overall cost structure, and I’m confident that we’re on track to achieve our goal of eliminating at least $1 billion in cumulative capital, operating and general and administrative costs by the end of next year compared with our earlier targeted timeline of 2020. Over the last few months, I’ve announced broad workforce changes that have resulted in a more streamlined Cenovus executive team, significantly fewer senior leadership positions and an overall staff reduction of approximately 15 percent. While letting good and talented people go is never easy, it has been necessary to align the size of our workforce with the work we have planned in the months ahead and to reduce costs. Despite the challenges Cenovus has faced over the past year, I strongly believe that with our current combination of top-tier assets and people, we now have an exceptional value creation opportunity. During my career, I‘ve had a successful track record of driving accountability, eliminating bureaucracy and creating value for shareholders, and in the coming months I look forward 2 | CENOVUS ENERGY 2017 TOTAL SHAREHOLDER RETURN 120 $110 100 $100 $90 80 $80 $70 60 $60 $50 40 $40 December 31, 2016 2016-12-30 March 31, 2017 2017-03-31 Cenovus Energy (TSX) June 30, 2017 2017-06-30 S&P TSX Composite Index September 30, 2017 2017-09-29 S&P TSX Energy Index December 31, 2017 2017-12-29 This chart shows cumulative shareholder return for $100 invested (assuming quarterly reinvestment of dividends), over the period December 31, 2016 to December 31, 2017. to working with our teams to target higher netbacks and increased cash flow. As we achieve our debt reduction goals, we will balance returning cash to shareholders with pursuing disciplined investments in high-return growth. We have much to look forward to in 2018. At Christina Lake, we’re making excellent headway with our 50,000 barrels-per-day phase G expansion, which is expected to have industry-leading go-forward capital efficiencies, well below our original forecasts. First oil is anticipated in the second half of 2019. While we’ve decided to scale back our original 2018 development plans in the Deep Basin due to weak natural gas prices and our near-term focus on paying down debt, the initial well results we’ve achieved since acquiring the assets have met or exceeded expectations. I believe our Deep Basin assets have significant potential to create value for Cenovus by providing short-cycle drilling opportunities that complement our longer-term oil sands investments. Our focus on technology development also continues to yield benefits for our business. For example, at our oil sands facilities, we’re successfully drilling longer horizontal wells, including some up to 1,600 metres, which is double our average well length just a few years ago. This means we can access the same amount of oil from fewer well pads. We’ve also implemented a new oil sands pad design that requires less infrastructure and a smaller footprint. These two developments alone have significantly reduced both our costs and the impact we have on the environment at our operations. In 2018 and beyond, we must also remain firmly focused on safety. I was deeply saddened by the death of one of our third-party contractors at Christina Lake earlier this year. We want to make sure everyone who works at our sites returns home safely at the end of each day, and that didn’t happen in this case. This tragedy took place on the heels of what was our best year ever for safety performance in 2017. It is a sobering reminder that we need to keep safety top of mind every day in everything that we do to ensure no one is injured while working for Cenovus. As I look at everything that Cenovus accomplished last year, I want to recognize the hard work and dedication of our staff. Their contributions have helped lay the foundation for what Cenovus is today, and what I believe it can be in the future – a company where employees want to work and that people want to invest in, one that’s focused on delivering results and increasing shareholder value. I look forward to working with the Cenovus management team and our excellent staff across the organization to achieve that vision. /s/ Alex Pourbaix ALEX POURBAIX President & Chief Executive Officer 2017 ANNUAL REPORT | 3 M E S S A G E F R O M O U R BOARD CHAIR Over the course of 2017, Cenovus evolved into a more diverse company with a stronger asset base. As a result of the asset acquisition we completed in May 2017, and the sale of our legacy conventional oil and natural gas assets, our upstream operations are now focused on two core areas – the oil sands and Deep Basin. This powerful portfolio of assets forms a solid foundation for years of potential cash flow and production growth. Last year, we also saw the price of oil recover to around US$60 a barrel by year-end, after reaching a low of nearly US$42 last summer. The benefit of that increase to heavy oil producers was somewhat offset by widening light-heavy oil differentials towards the end of 2017 and into 2018. We were also encouraged by progress achieved on key pipeline projects, such as the Trans Mountain Expansion and Enbridge Line 3 Replacement Program as well as approvals in the U.S. for Keystone XL, and we remain optimistic that these projects are well on their way to completion. These are positive developments for Cenovus. Shortly after we completed our acquisition last May, several members of the Board and I went on the road to hear directly from some of our largest shareholders. They emphasized that they think we have among the best assets and people in the business and the potential to be a top-tier performer in our industry. But they and other shareholders are unhappy, largely because we have underperformed our peers in terms of total shareholder return for some time. We also heard consistently that we need to prove our expertise in the Deep Basin and move quickly to deleverage our balance sheet. Over the last few months, Cenovus has made considerable progress in reducing debt and adapting our organization to today’s environment. Despite this progress, it remains our job to continue to earn your confidence by further strengthening our balance sheet, reducing costs, driving increased cash flow and providing returns to shareholders. Last year, the Board completed a global search for a new Chief Executive Officer. We were looking for someone with extensive management experience and the ability to unlock significant additional value from Cenovus’s portfolio. After an exhaustive review, we chose Alex Pourbaix who has an impressive track record of leadership in the Canadian energy industry spanning nearly three decades. Alex is committed to realizing Cenovus’s potential and driving value for shareholders from Cenovus’s existing asset base. 4 | CENOVUS ENERGY We also conducted a search for highly-qualified new Board candidates, and I’m pleased that Hal Kvisle and Keith MacPhail, who bring a wealth of oil and gas experience both at the Board and executive level, have agreed to be proposed nominees for election to the Board at Cenovus’s annual general meeting this April. With these nominations, as well as the addition of six other new directors over the past three years, Cenovus continues to make significant progress with the Board renewal process launched in 2014. The renewal process focuses on orderly succession of directors while maintaining an appropriate balance and diversity of skills, experience, tenure and fresh perspectives. Your Board remains well positioned to provide Cenovus with sound oversight and possesses executive-level experience in upstream operations, marketing and transportation, the power and pipeline sectors, refining, capital markets and human resource management. On behalf of the Board and the entire company, I’d like to thank Brian Ferguson for his years of thoughtful leadership and dedication to Cenovus and its predecessor companies. Brian retired as Chief Executive Officer last November. I’d also like to thank Ian Delaney, who will retire as a director at the end of this year’s annual meeting, as well as Michael Grandin and Valerie Nielsen, who retired as Board Chair and director, respectively, at the end of last year’s annual meeting, for their many years of service. In closing, I believe Cenovus has an exceptional asset base, strong management team and talented staff and is on track to achieve its goals. Shareholders should have confidence that the Board will provide management with clear strategic direction in 2018 and beyond. Sincerely, on behalf of the Board, /s/ Patrick Daniel PATRICK DANIEL Board Chair MANAGEMENT’S DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2017 6 8 9 11 13 18 OVERVIEW OF CENOVUS 30 DISCONTINUED OPERATIONS 2017 HIGHLIGHTS OPERATING RESULTS COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS FINANCIAL RESULTS REPORTABLE SEGMENTS 19 OIL SANDS 23 DEEP BASIN 26 REFINING AND MARKETING 27 CORPORATE AND ELIMINATIONS 33 QUARTERLY RESULTS 36 OIL AND GAS RESERVES 37 41 57 LIQUIDITY AND CAPITAL RESOURCES RISK MANAGEMENT AND RISK FACTORS CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES 60 CONTROL ENVIRONMENT 61 61 CORPORATE RESPONSIBILITY OUTLOOK This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, mean Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated February 14, 2018, should be read in conjunction with December 31, 2017 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”). All of the information and statements contained in this MD&A are made as of February 14, 2018, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. The information in this MD&A, as it relates to our operations for 2017, reflects the closing of the Acquisition (as defined in this MD&A) on May 17, 2017. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (the “Board”) reviewed and recommended the MD&A for approval by the Board, which occurred on February 14, 2018. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A. Basis of Presentation This MD&A and the Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board (“IASB”). Production volumes are presented on a before royalties basis. Non-GAAP Measures and Additional Subtotals Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow, Operating Earnings, Free Funds Flow, Debt, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) and therefore are considered non-GAAP measures. In addition, Operating Margin is considered an additional subtotal found in Notes 1 and 11 of our Consolidated Financial Statements. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation, if applicable, of each non-GAAP measure or additional subtotal is presented in the Operating Results, Financial Results, Liquidity and Capital Resources, or Advisory sections of this MD&A. 2017 ANNUAL REPORT | 5 OVERVIEW OF CENOVUS Executional Excellence We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On December 31, 2017, we had an enterprise value of approximately $24 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in western Canada. We also conduct marketing activities and have refining operations in the United States (“U.S.”). Our average crude oil and NGLs (collectively, “liquids”) production in 2017 was 360,704 barrels per day, our average natural gas production was 659 MMcf per day, and our total production was 470,490 BOE per day. The refining operations processed an average of 442,000 gross barrels per day of crude oil feedstock into an average of 470,000 gross barrels per day of refined products. Year in Review 2017 was a year of significant change for Cenovus, where we gained full ownership of our oil sands assets, acquired an additional core operating area in the Deep Basin and divested the majority of our legacy Conventional assets. On May 17, 2017, we acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) their 50 percent interest in the FCCL Partnership (“FCCL”), and the majority of ConocoPhillips’ western Canadian conventional assets in the Deep Basin in Alberta and British Columbia for total consideration of $17.9 billion (“the Acquisition”). The Acquisition effectively doubled our oil sands production and proved bitumen reserves. In addition, we acquired more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia (collectively, the “Deep Basin Assets”). The Deep Basin Assets are expected to provide short-cycle development opportunities with high-return potential that complement our long-cycle oil sands investments. The purchase consideration included US$10.6 billion in cash, before adjustments, and 208 million Cenovus common shares. The cash portion of the consideration was funded through a combination of cash on hand, a draw on our existing committed credit facility, an offering of senior unsecured notes (US$2.9 billion), a committed asset-sale bridge credit facility ($3.6 billion) (“Bridge Facility”), and a bought-deal common share offering ($3.0 billion). In the second half of 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for aggregate gross cash proceeds of approximately $3.2 billion. The net proceeds and cash on hand were used to fully repay and retire the Bridge Facility. The sale of Suffield, our remaining legacy Conventional segment asset, closed on January 5, 2018 for gross proceeds of $512 million. In aggregate, gross proceeds for all legacy Conventional crude oil and natural gas assets divested was $3.7 billion, before closing adjustments, and resulted in a before-tax gain on discontinuance of approximately $1.6 billion, of which $1.3 billion was recorded in 2017. In December 2017, we also commenced marketing for sale certain non-core assets located in the East and West Clearwater areas of the Deep Basin, representing approximately 15,000 BOE per day of production, to further streamline our portfolio and deleverage our balance sheet. Over the course of 2017, Cenovus has transitioned its asset base and strategy to support focused development in the oil sands and Deep Basin, providing opportunities for disciplined growth and long-term cash flow generation. At the same time, investor concern about the Acquisition, volatile commodity prices and a number of other factors contributed to a more than 40 percent decline in our share price. Over the last few months, Cenovus has made considerable progress in reducing debt and is taking steps to right-size the Company for the current environment. Effective November 6, 2017, Alex Pourbaix was appointed Cenovus’s President and Chief Executive Officer, and he subsequently announced changes to the senior leadership team in December 2017. Cenovus’s 2018 budget was announced in December, with total capital expenditures expected to be between $1.5 billion and $1.7 billion. This budget reflects Cenovus’s focus on capital discipline, cost reductions and deleveraging. Our Strategy Our strategy is to increase cash flows through disciplined production growth from our industry-leading portfolio of oil sands and Deep Basin natural gas and liquids assets in western Canada. We are focused on increasing our current share price and maximizing shareholder value through cost leadership and realizing the best margins for our products to help us maintain financial resilience and deliver sustainable dividend growth. We plan to achieve our strategy by drawing on the expertise of our people and leveraging our strategic differentiators: premium asset quality, executional excellence, value-added integration, focused innovation and trusted reputation. Our Key Strategic Differentiators Premium Asset Quality Cenovus has a deep portfolio of premium-quality oil sands, natural gas and NGLs assets that we believe provide us with significant cost and environmental performance advantages. Our in-situ oil sands projects and Deep Basin Assets in western Canada offer long and short-cycle opportunities that provide the capital investment flexibility to position us to deliver value growth at various points of the price cycle. In addition to our exploration and production assets, we have complementary interests in refineries and product transportation infrastructure. 6 | CENOVUS ENERGY Our team is committed to delivering on our business plan in a safe, disciplined and responsible manner and continuously improving our performance to help manage risk and optimize returns. We use a manufacturing approach to support consistent performance and enhance reliability. This involves applying standardized and repeatable designs and processes to the construction and operation of our facilities to reduce costs and improve efficiencies at all project stages. We strive to execute our work in an agile manner with a focus on using our resources effectively. Value-Added Integration Our integrated business approach helps provide stability to our cash flows and maximize value for the oil and natural gas we produce. Having ownership in oil refineries positions us to capture the full value chain from production to high-quality end products like transportation fuels. In addition, our pipeline commitments, crude-by-rail loading facility and product marketing activities assist us to obtain global pricing for our oil. As a consumer of natural gas at our oil sands facilities and refineries, our natural gas production acts as an economic hedge to help manage price volatility. In addition, our cogeneration plants efficiently provide power for our oil sands facilities with the added value of excess electricity being sold to the Alberta electricity grid. We focus our innovation efforts on accelerating the adoption of technology solutions and methods of operating to enhance safety, reduce costs, improve margins and lower emissions. We expect innovation at Cenovus to mean significant improvements and game-changing developments that are implemented to generate value. We aim to complement our internal technology development efforts with external collaboration that will leverage our Focused Innovation technology spend. Trusted Reputation We are a responsible, progressive company that is committed to providing a safe and healthy workplace, building strong external relationships, minimizing our environmental footprint and being a part of a lower carbon future. Our actions are intended to support our trusted reputation and enable us to attract and retain top-quality staff and to engage with and be respected by our stakeholders: investors, the communities in which we operate, environmental groups, governments, Aboriginal people, media, project partners and the general public. We measure our performance through a scorecard that reflects our financial, operational, safety, environmental and organizational health goals. Our Operations Oil Sands Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northern Alberta, including Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake are producing, while Narrows Lake is in the initial stages of development. These three projects are located in the Athabasca region of northeastern Alberta, and our project at Telephone Lake is located within the Borealis region of northeastern Alberta. The Oil Sands segment also includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations. ($ millions) Operating Margin Capital Investment Deep Basin Operating Margin Net of Related Capital Investment ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Our Deep Basin Assets include approximately three million net acres of land rich in natural gas, condensate and other NGLs, and light and medium oil. The assets are located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and Alberta, and include interests in numerous natural gas processing facilities. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement our long-term oil sands development and provide an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations. 2017 Crude Oil Natural Gas 2,231 969 1,262 1 4 (3) May 17 – December 31, 2017 207 225 (18) OVERVIEW OF CENOVUS Executional Excellence We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On December 31, 2017, we had an enterprise value of approximately $24 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in western Canada. We also conduct marketing activities and have refining operations in the United States (“U.S.”). Our average crude oil and NGLs (collectively, “liquids”) production in 2017 was 360,704 barrels per day, our average natural gas production was 659 MMcf per day, and our total production was 470,490 BOE per day. The refining operations processed an average of 442,000 gross barrels per day of crude oil feedstock into an average of 470,000 gross barrels per day of refined products. Year in Review 2017 was a year of significant change for Cenovus, where we gained full ownership of our oil sands assets, acquired an additional core operating area in the Deep Basin and divested the majority of our legacy Conventional assets. On May 17, 2017, we acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) their 50 percent interest in the FCCL Partnership (“FCCL”), and the majority of ConocoPhillips’ western Canadian conventional assets in the Deep Basin in Alberta and British Columbia for total consideration of $17.9 billion (“the Acquisition”). The Acquisition effectively doubled our oil sands production and proved bitumen reserves. In addition, we acquired more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia (collectively, the “Deep Basin Assets”). The Deep Basin Assets are expected to provide short-cycle development opportunities with high-return potential that complement our long-cycle oil sands investments. The purchase consideration included US$10.6 billion in cash, before adjustments, and 208 million Cenovus common shares. The cash portion of the consideration was funded through a combination of cash on hand, a draw on our existing committed credit facility, an offering of senior unsecured notes (US$2.9 billion), a committed asset-sale bridge credit facility ($3.6 billion) (“Bridge Facility”), and a bought-deal common share offering ($3.0 billion). In the second half of 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for aggregate gross cash proceeds of approximately $3.2 billion. The net proceeds and cash on hand were used to fully repay and retire the Bridge Facility. The sale of Suffield, our remaining legacy Conventional segment asset, closed on January 5, 2018 for gross proceeds of $512 million. In aggregate, gross proceeds for all legacy Conventional crude oil and natural gas assets divested was $3.7 billion, before closing adjustments, and resulted in a before-tax gain on discontinuance of approximately $1.6 billion, of which $1.3 billion was recorded in 2017. In December 2017, we also commenced marketing for sale certain non-core assets located in the East and West Clearwater areas of the Deep Basin, representing approximately 15,000 BOE per day of production, to further streamline our portfolio and deleverage our balance sheet. Over the course of 2017, Cenovus has transitioned its asset base and strategy to support focused development in the oil sands and Deep Basin, providing opportunities for disciplined growth and long-term cash flow generation. At the same time, investor concern about the Acquisition, volatile commodity prices and a number of other factors contributed to a more than 40 percent decline in our share price. Over the last few months, Cenovus has made considerable progress in reducing debt and is taking steps to right-size the Company for the current environment. Effective November 6, 2017, Alex Pourbaix was appointed Cenovus’s President and Chief Executive Officer, and he subsequently announced changes to the senior leadership team in December 2017. Cenovus’s 2018 budget was announced in December, with total capital expenditures expected to be between $1.5 billion and $1.7 billion. This budget reflects Cenovus’s focus on capital discipline, cost reductions and deleveraging. Our Strategy Our strategy is to increase cash flows through disciplined production growth from our industry-leading portfolio of oil sands and Deep Basin natural gas and liquids assets in western Canada. We are focused on increasing our current share price and maximizing shareholder value through cost leadership and realizing the best margins for our products to help us maintain financial resilience and deliver sustainable dividend growth. We plan to achieve our strategy by drawing on the expertise of our people and leveraging our strategic differentiators: premium asset quality, executional excellence, value-added integration, focused innovation and trusted reputation. Our Key Strategic Differentiators Premium Asset Quality Cenovus has a deep portfolio of premium-quality oil sands, natural gas and NGLs assets that we believe provide us with significant cost and environmental performance advantages. Our in-situ oil sands projects and Deep Basin Assets in western Canada offer long and short-cycle opportunities that provide the capital investment flexibility to position us to deliver value growth at various points of the price cycle. In addition to our exploration and production assets, we have complementary interests in refineries and product transportation infrastructure. Our team is committed to delivering on our business plan in a safe, disciplined and responsible manner and continuously improving our performance to help manage risk and optimize returns. We use a manufacturing approach to support consistent performance and enhance reliability. This involves applying standardized and repeatable designs and processes to the construction and operation of our facilities to reduce costs and improve efficiencies at all project stages. We strive to execute our work in an agile manner with a focus on using our resources effectively. Value-Added Integration Our integrated business approach helps provide stability to our cash flows and maximize value for the oil and natural gas we produce. Having ownership in oil refineries positions us to capture the full value chain from production to high-quality end products like transportation fuels. In addition, our pipeline commitments, crude-by-rail loading facility and product marketing activities assist us to obtain global pricing for our oil. As a consumer of natural gas at our oil sands facilities and refineries, our natural gas production acts as an economic hedge to help manage price volatility. In addition, our cogeneration plants efficiently provide power for our oil sands facilities with the added value of excess electricity being sold to the Alberta electricity grid. Focused Innovation We focus our innovation efforts on accelerating the adoption of technology solutions and methods of operating to enhance safety, reduce costs, improve margins and lower emissions. We expect innovation at Cenovus to mean significant improvements and game-changing developments that are implemented to generate value. We aim to complement our internal technology development efforts with external collaboration that will leverage our technology spend. Trusted Reputation We are a responsible, progressive company that is committed to providing a safe and healthy workplace, building strong external relationships, minimizing our environmental footprint and being a part of a lower carbon future. Our actions are intended to support our trusted reputation and enable us to attract and retain top-quality staff and to engage with and be respected by our stakeholders: investors, the communities in which we operate, environmental groups, governments, Aboriginal people, media, project partners and the general public. We measure our performance through a scorecard that reflects our financial, operational, safety, environmental and organizational health goals. Our Operations Oil Sands Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northern Alberta, including Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake are producing, while Narrows Lake is in the initial stages of development. These three projects are located in the Athabasca region of northeastern Alberta, and our project at Telephone Lake is located within the Borealis region of northeastern Alberta. The Oil Sands segment also includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations. ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Deep Basin 2017 Crude Oil Natural Gas 2,231 969 1,262 1 4 (3) Our Deep Basin Assets include approximately three million net acres of land rich in natural gas, condensate and other NGLs, and light and medium oil. The assets are located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and Alberta, and include interests in numerous natural gas processing facilities. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement our long-term oil sands development and provide an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations. ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment May 17 – December 31, 2017 207 225 (18) 2017 ANNUAL REPORT | 7 Conventional All references to our legacy Conventional segment are accounted for as a discontinued operation. In late 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for gross cash proceeds totaling approximately $3.2 billion, resulting in a net before-tax gain on discontinuance of approximately $1.3 billion. The sale of our remaining Conventional segment asset, Suffield, closed on January 5, 2018 for gross proceeds of $512 million and resulted in a before-tax gain on sale of approximately $350 million. The Conventional segment produced crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and tight oil opportunities in the Palliser block in southern Alberta. ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Refining and Marketing 2017 Liquids Natural Gas 360 195 165 124 11 113 Our operations include two refineries located in Illinois and Texas that are jointly owned with (50 percent interest) and operated by Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River and Borger refineries (the “Refineries”) is approximately 314,000 barrels per day and 146,000 barrels per day, respectively. This includes processing capability of up to 255,000 gross barrels per day of blended heavy crude oil. The refining operations allow us to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American light/heavy crude oil price differential fluctuations. This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and the marketing of third-party purchases and sales of product undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification. ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment 2017 HIGHLIGHTS 2017 598 180 418 In 2017, we completed the Acquisition which gave us full ownership of our oil sands operations and provided an additional core operating area with the Deep Basin Assets. Including the Suffield divestiture which closed on January 5, 2018, all of our legacy Conventional oil and gas assets have been sold for combined gross cash proceeds of $3.7 billion. Gross proceeds received prior to December 31, 2017 of $3.2 billion, combined with cash on hand, were used to fully repay and retire the $3.6 billion Bridge Facility that was drawn to help fund the Acquisition. Crude oil prices continued to be volatile throughout the year. West Texas Intermediate (“WTI”) benchmark crude price ranged from a high of US$60.42 per barrel to a low of US$42.53 per barrel and averaged 18 percent higher compared with 2016. Western Canadian Select (“WCS”), a blended heavy oil benchmark, ranged from a high of US$44.79 per barrel to a low of US$29.56 per barrel, while averaging 32 percent higher in 2017 compared to 2016. In addition, natural gas prices were very volatile, ranging from a high of $3.75 per Mcf to a low of $1.07 per Mcf; however, still averaging 16 percent higher than 2016. In 2017, we: • • Produced 470,490 BOE per day, a 73 percent increase from 2016; Earned an average companywide Netback from continuing operations of $20.89 per BOE, before realized hedging, an increase of 78 percent from 2016; Generated upstream operating margin, excluding the Conventional segment, of $2,394 million compared with $877 million in 2016 primarily due to the Acquisition, a rise in sales volumes and higher liquids sales prices; Achieved cash from operating activities and Adjusted Funds Flow of $3,059 million and $2,914 million, respectively, increasing significantly from 2016; Recorded a $275 million tax recovery as a result of the U.S. federal corporate income tax rate change announced in 2017; Recorded Net Earnings from continuing operations of $2,268 million (2016 – Net Loss from continuing operations of $459 million); Invested $1,661 million in capital which allowed us to generate Free Funds Flow of $1,253 million, a threefold increase from $397 million in 2016; • • • • • 8 | CENOVUS ENERGY • • • • Divested of the majority of our legacy Conventional crude oil and natural gas assets, recognizing a before-tax gain of $1.3 billion in discontinued operations; Announced the appointment of Alex Pourbaix as President and Chief Executive Officer in November, and announced changes to the senior leadership team in December; Re-evaluated our oil sands Exploration & Evaluation (“E&E”) projects in line with our current business plans. As a result, we wrote off $887 million in the fourth quarter as exploration expense; and Announced our 2018 budget in December, focusing on capital discipline, cost reductions and deleveraging. Our upstream assets continued to perform well in 2017. Total production increased primarily due to the Acquisition, slightly offset by the disposition of legacy Conventional assets late in the year. OPERATING RESULTS Production Volumes Continuing Operations Liquids (barrels per day) Oil Sands Foster Creek Christina Lake Deep Basin Light and Medium Oil NGLs Natural Gas (MMcf per day) Oil Sands Deep Basin Production From Discontinued Operations (Conventional) Liquids (barrels per day) Heavy Oil Light and Medium Oil NGLs Natural Gas (MMcf per day) Production From 2017 Percent Change 2016 Percent Change 2015 124,752 167,727 292,479 3,922 16,928 20,850 78% 111% 95% -% -% -% 10 316 326 - (41)% -% 1,818% -% 70,244 79,449 149,693 - - - 17 - 17 - 7% 6% 7% -% -% -% 7% (11)% -% (11)% 65,345 74,975 140,320 - - - 19 - 19 Liquids Production (barrels per day) 313,329 109% 149,693 140,320 Conventional Production (BOE per day) -% 4,163 Continuing Operations (BOE per day) 367,635 141% 152,527 3% 147,701 21,478 24,824 1,073 47,375 333 (26)% (4)% 1% (16)% (12)% 29,185 25,915 1,065 56,165 377 (15)% (10)% (7)% (12)% (8)% 34,256 28,675 1,149 64,080 412 Discontinued Operations (BOE per day) 102,855 (14)% 118,998 (10)% 132,746 Total Production (BOE per day) 470,490 73% 271,525 (3)% 280,447 In 2017, Oil Sands production increased primarily as a result of the Acquisition. Incremental production at Foster Creek and Christina Lake from May 17, 2017, the closing date of the Acquisition, until December 31, 2017 was 76,748 barrels per day and 102,945 barrels per day, respectively. Foster Creek also had incremental production volumes related to the phase G expansion, partially offset by reduced volumes as a result of temporary treating issues and a 20-day planned plant turnaround. The phase F expansion at Christina Lake contributed incremental production volumes. Total production in the Deep Basin averaged 117,138 BOE per day for the period of May 17, 2017 to December 31, 2017. Incremental volumes due to the drilling and completion of horizontal production wells in the second half of the year was partially offset by downtime associated with third-party pipeline and facility outages. Prior to the dispositions, our Conventional liquids production was lower than in 2016 primarily due to expected natural declines partially offset by new production from our tight oil drilling program in the first half of 2017, before growth capital was reduced as a result of the decision to divest the Palliser asset. Our Conventional natural gas production decreased in 2017, relative to the same period in 2016 due to expected natural declines. Conventional All references to our legacy Conventional segment are accounted for as a discontinued operation. In late 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for gross cash proceeds totaling approximately $3.2 billion, resulting in a net before-tax gain on discontinuance of approximately $1.3 billion. The sale of our remaining Conventional segment asset, Suffield, closed on January 5, 2018 for gross proceeds of $512 million and resulted in a before-tax gain on sale of approximately $350 million. The Conventional segment produced crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and tight oil opportunities in the Palliser block in southern Alberta. ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Refining and Marketing 2017 Liquids Natural Gas 360 195 165 124 11 113 Our operations include two refineries located in Illinois and Texas that are jointly owned with (50 percent interest) and operated by Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River and Borger refineries (the “Refineries”) is approximately 314,000 barrels per day and 146,000 barrels per day, respectively. This includes processing capability of up to 255,000 gross barrels per day of blended heavy crude oil. The refining operations allow us to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American light/heavy crude oil price differential fluctuations. This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and the marketing of third-party purchases and sales of product undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification. ($ millions) Operating Margin Capital Investment 2017 HIGHLIGHTS Operating Margin Net of Related Capital Investment 2017 598 180 418 In 2017, we completed the Acquisition which gave us full ownership of our oil sands operations and provided an additional core operating area with the Deep Basin Assets. Including the Suffield divestiture which closed on January 5, 2018, all of our legacy Conventional oil and gas assets have been sold for combined gross cash proceeds of $3.7 billion. Gross proceeds received prior to December 31, 2017 of $3.2 billion, combined with cash on hand, were used to fully repay and retire the $3.6 billion Bridge Facility that was drawn to help fund the Acquisition. Crude oil prices continued to be volatile throughout the year. West Texas Intermediate (“WTI”) benchmark crude price ranged from a high of US$60.42 per barrel to a low of US$42.53 per barrel and averaged 18 percent higher compared with 2016. Western Canadian Select (“WCS”), a blended heavy oil benchmark, ranged from a high of US$44.79 per barrel to a low of US$29.56 per barrel, while averaging 32 percent higher in 2017 compared to 2016. In addition, natural gas prices were very volatile, ranging from a high of $3.75 per Mcf to a low of $1.07 per Mcf; however, still averaging 16 percent higher than 2016. In 2017, we: • • • • • • • Produced 470,490 BOE per day, a 73 percent increase from 2016; Earned an average companywide Netback from continuing operations of $20.89 per BOE, before realized hedging, an increase of 78 percent from 2016; Generated upstream operating margin, excluding the Conventional segment, of $2,394 million compared with $877 million in 2016 primarily due to the Acquisition, a rise in sales volumes and higher liquids sales prices; Achieved cash from operating activities and Adjusted Funds Flow of $3,059 million and $2,914 million, respectively, increasing significantly from 2016; Recorded a $275 million tax recovery as a result of the U.S. federal corporate income tax rate change Recorded Net Earnings from continuing operations of $2,268 million (2016 – Net Loss from continuing Invested $1,661 million in capital which allowed us to generate Free Funds Flow of $1,253 million, a threefold announced in 2017; operations of $459 million); increase from $397 million in 2016; • • • • Divested of the majority of our legacy Conventional crude oil and natural gas assets, recognizing a before-tax gain of $1.3 billion in discontinued operations; Announced the appointment of Alex Pourbaix as President and Chief Executive Officer in November, and announced changes to the senior leadership team in December; Re-evaluated our oil sands Exploration & Evaluation (“E&E”) projects in line with our current business plans. As a result, we wrote off $887 million in the fourth quarter as exploration expense; and Announced our 2018 budget in December, focusing on capital discipline, cost reductions and deleveraging. OPERATING RESULTS Our upstream assets continued to perform well in 2017. Total production increased primarily due to the Acquisition, slightly offset by the disposition of legacy Conventional assets late in the year. Liquids Production (barrels per day) 313,329 109% 149,693 Production Volumes Continuing Operations Liquids (barrels per day) Oil Sands Foster Creek Christina Lake Deep Basin Light and Medium Oil NGLs Natural Gas (MMcf per day) Oil Sands Deep Basin Conventional Production (BOE per day) Production From Continuing Operations (BOE per day) Discontinued Operations (Conventional) Liquids (barrels per day) Heavy Oil Light and Medium Oil NGLs Natural Gas (MMcf per day) Production From Discontinued Operations (BOE per day) 2017 Percent Change 2016 Percent Change 2015 124,752 167,727 292,479 3,922 16,928 20,850 78% 111% 95% -% -% -% 70,244 79,449 149,693 - - - 10 316 326 - (41)% -% 1,818% -% 17 - 17 - 7% 6% 7% -% -% -% 7% (11)% -% (11)% 65,345 74,975 140,320 - - - 140,320 19 - 19 -% 4,163 367,635 141% 152,527 3% 147,701 21,478 24,824 1,073 47,375 333 (26)% (4)% 1% (16)% (12)% 29,185 25,915 1,065 56,165 377 (15)% (10)% (7)% (12)% (8)% 34,256 28,675 1,149 64,080 412 102,855 (14)% 118,998 (10)% 132,746 Total Production (BOE per day) 470,490 73% 271,525 (3)% 280,447 In 2017, Oil Sands production increased primarily as a result of the Acquisition. Incremental production at Foster Creek and Christina Lake from May 17, 2017, the closing date of the Acquisition, until December 31, 2017 was 76,748 barrels per day and 102,945 barrels per day, respectively. Foster Creek also had incremental production volumes related to the phase G expansion, partially offset by reduced volumes as a result of temporary treating issues and a 20-day planned plant turnaround. The phase F expansion at Christina Lake contributed incremental production volumes. Total production in the Deep Basin averaged 117,138 BOE per day for the period of May 17, 2017 to December 31, 2017. Incremental volumes due to the drilling and completion of horizontal production wells in the second half of the year was partially offset by downtime associated with third-party pipeline and facility outages. Prior to the dispositions, our Conventional liquids production was lower than in 2016 primarily due to expected natural declines partially offset by new production from our tight oil drilling program in the first half of 2017, before growth capital was reduced as a result of the decision to divest the Palliser asset. Our Conventional natural gas production decreased in 2017, relative to the same period in 2016 due to expected natural declines. 2017 ANNUAL REPORT | 9 Oil and Gas Reserves Based on our reserves report prepared by independent qualified reserves evaluators (“IQREs”), our proved bitumen reserves increased 103 percent to approximately 4.75 billion barrels and our proved plus probable bitumen reserves increased 92 percent to approximately 6.38 billion barrels. Our Deep Basin proved reserves were 410 MMBOE and our proved plus probable reserves were 660 MMBOE. COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. Selected Benchmark Prices and Exchange Rates (1) Netbacks From Continuing Operations Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see the Advisory section of this MD&A. ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Production and Mineral Taxes Netback Excluding Realized Risk Management (1) Realized Risk Management Gain (Loss) Netback Including Realized Risk Management (1) 2017 36.86 2.07 5.43 8.46 0.01 20.89 (2.35) 18.54 2016 27.37 0.17 6.51 8.94 - 11.75 3.22 14.97 2015 30.81 0.56 6.34 9.94 0.03 13.94 7.60 21.54 (1) Excludes results from our Conventional segment, which has been classified as a discontinued operation. Our average Netback improved primarily due to higher liquids sales prices, partially offset by increased royalties and the strengthening of the Canadian dollar relative to the U.S. dollar. The strengthening of the Canadian dollar compared with 2016 had a negative impact on our sales price of approximately $0.78 per BOE. Refining and Marketing Crude oil runs and refined product output in 2017 remained consistent compared with 2016. The planned and unplanned maintenance at both Refineries in 2017 had a similar impact on crude oil runs and refined product output as the planned and unplanned maintenance in 2016. Crude Oil Runs (1) (Mbbls/d) Heavy Crude Oil (1) Refined Product (1) (Mbbls/d) Crude Utilization (1) (percent) 2017 442 202 470 96 Percent Change -% -% (1)% 2016 Percent Change 2015 444 233 471 97 6% 17% 6% 6% 419 200 444 91 (13)% (1) Represents 100 percent of the Wood River and Borger refinery operations. In 2017, Operating Margin from our Refining and Marketing segment increased 73 percent compared with 2016 due to higher average market crack spreads and increased margins on the sale of our secondary products due to higher realized pricing. These increases were partially offset by narrowing heavy crude oil differentials, which increase crude input costs to the refinery, and the strengthening of the Canadian dollar relative to the U.S. dollar. Further information on the changes in our production volumes, items included in our Netbacks and refining results can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements. 10 | CENOVUS ENERGY (US$/bbl, unless otherwise indicated) Q4 2017 Q4 2016 2017 Percent Change 2016 2015 Crude Oil Prices Brent Average End of Period WTI Average End of Period WCS Average Average (C$/bbl) End of Period Average Differential Brent-WTI Average Differential WTI-WCS Condensate (C5 @ Edmonton) Average (2) Average Differential WTI-Condensate (Premium)/Discount Average Differential WCS-Condensate (Premium)/Discount Mixed Sweet Blend (“MSW” @ Edmonton) Average (3) End of Period Average Refined Product Prices Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Margin: Average 3-2-1 Crack Spreads (4) Chicago Average Natural Gas Prices AECO (C$/Mcf) (5) NYMEX (US$/Mcf) Basis Differential NYMEX-AECO (US$/Mcf) Foreign Exchange Rate (US$ per C$1) 61.54 66.87 55.40 60.42 6.14 43.14 54.84 34.93 12.26 51.13 56.82 49.29 53.72 1.84 34.97 46.63 38.81 14.32 54.82 66.87 50.95 60.42 3.87 38.97 50.56 34.93 11.98 22% 18% 18% 12% 125% 32% 29% (10)% (13)% 57.97 48.33 51.57 21% 42.47 47.36 (2.57) 0.96 (0.62) (173)% 0.85 1.44 (14.83) (13.36) (12.60) (3)% (12.99) (12.08) 54.26 53.03 74.36 80.58 46.18 51.26 59.46 61.50 48.49 53.03 66.95 69.09 21.09 10.96 16.77 28% 13.07 19.11 1.96 2.93 1.40 2.81 2.98 0.86 2.43 3.11 1.26 2.09 2.46 0.89 2.77 2.66 0.49 21% 3% 19% 23% 16% 26% 42% 45.04 56.82 43.32 53.72 1.72 29.48 39.05 38.81 13.84 40.11 51.26 56.24 56.33 53.64 37.28 48.80 37.04 4.84 35.28 45.12 24.98 13.52 45.32 34.98 67.68 68.12 Average 0.787 0.750 0.771 2% 0.755 0.782 (1) These benchmark prices are not our realized sales prices. For our average realized sales prices and realized risk management results, refer to the Netbacks tables in the Operating Results, Reportable Segments and Discontinued Operations sections of this MD&A. (2) The average Canadian dollar condensate benchmark price for 2017 was $66.89 per barrel (2016 – $56.25 per barrel; 2015 – $60.56 per barrel); fourth quarter average condensate benchmark price was $73.66 per barrel (2016 – $64.44 per barrel). (3) The average Canadian dollar MSW benchmark price for 2017 was $62.89 per barrel (2016 – $53.13 per barrel; 2015 – $57.95 per barrel); fourth quarter average Canadian dollar MSW benchmark price was $68.95 per barrel (2016 – $61.57 per barrel). The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis. (4) (5) Alberta Energy Company (“AECO”) natural gas. Crude Oil Benchmarks The average Brent, WTI and WCS benchmark prices improved in 2017. Compliance with the production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) led to widespread market expectations of an accelerated return to normal inventory levels. However, without supporting supply and demand drivers, prices continued to be volatile in 2017 as growing supply from the U.S., unstable supply from Libya and Nigeria, severe weather related incidents, and strong global demand resulted in varying expectations on the pace of crude oil and refined product inventory draws. WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. In 2017, WTI benchmark prices weakened relative to Brent compared with 2016 due to growing U.S. crude oil supply and refinery disruptions from hurricanes in the U.S. Gulf Coast resulting in increased crude oil inventories. WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed in 2017 compared with 2016. WCS strengthened relative to WTI due to a temporary decrease in supply of blended heavy oil in Alberta and OPEC’s compliance with production cuts reducing global heavy oil supply. Oil and Gas Reserves Based on our reserves report prepared by independent qualified reserves evaluators (“IQREs”), our proved bitumen reserves increased 103 percent to approximately 4.75 billion barrels and our proved plus probable bitumen reserves increased 92 percent to approximately 6.38 billion barrels. Our Deep Basin proved reserves were 410 MMBOE and our proved plus probable reserves were 660 MMBOE. COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. Selected Benchmark Prices and Exchange Rates (1) Netbacks From Continuing Operations Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see the Advisory section of this MD&A. ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Production and Mineral Taxes Netback Excluding Realized Risk Management (1) Realized Risk Management Gain (Loss) Netback Including Realized Risk Management (1) 2017 36.86 2.07 5.43 8.46 0.01 20.89 (2.35) 18.54 2016 27.37 0.17 6.51 8.94 - 11.75 3.22 14.97 (1) Excludes results from our Conventional segment, which has been classified as a discontinued operation. Our average Netback improved primarily due to higher liquids sales prices, partially offset by increased royalties and the strengthening of the Canadian dollar relative to the U.S. dollar. The strengthening of the Canadian dollar compared with 2016 had a negative impact on our sales price of approximately $0.78 per BOE. Refining and Marketing Crude oil runs and refined product output in 2017 remained consistent compared with 2016. The planned and unplanned maintenance at both Refineries in 2017 had a similar impact on crude oil runs and refined product output as the planned and unplanned maintenance in 2016. Crude Oil Runs (1) (Mbbls/d) Heavy Crude Oil (1) Refined Product (1) (Mbbls/d) Crude Utilization (1) (percent) 2017 442 202 470 96 Percent Change -% -% (1)% 2016 444 471 97 Percent Change 6% 6% 6% (13)% 17% 200 233 (1) Represents 100 percent of the Wood River and Borger refinery operations. In 2017, Operating Margin from our Refining and Marketing segment increased 73 percent compared with 2016 due to higher average market crack spreads and increased margins on the sale of our secondary products due to higher realized pricing. These increases were partially offset by narrowing heavy crude oil differentials, which increase crude input costs to the refinery, and the strengthening of the Canadian dollar relative to the U.S. dollar. Further information on the changes in our production volumes, items included in our Netbacks and refining results can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements. 2015 30.81 0.56 6.34 9.94 0.03 13.94 7.60 21.54 2015 419 444 91 (US$/bbl, unless otherwise indicated) Q4 2017 Q4 2016 2017 Percent Change 2016 2015 Crude Oil Prices Brent Average End of Period WTI Average End of Period Average Differential Brent-WTI WCS Average Average (C$/bbl) End of Period Average Differential WTI-WCS Condensate (C5 @ Edmonton) Average (2) Average Differential WTI-Condensate (Premium)/Discount Average Differential WCS-Condensate (Premium)/Discount Mixed Sweet Blend (“MSW” @ Edmonton) Average (3) End of Period Average Refined Product Prices Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Margin: Average 3-2-1 Crack Spreads (4) Chicago Average Natural Gas Prices AECO (C$/Mcf) (5) NYMEX (US$/Mcf) Basis Differential NYMEX-AECO (US$/Mcf) Foreign Exchange Rate (US$ per C$1) 61.54 66.87 55.40 60.42 6.14 43.14 54.84 34.93 12.26 51.13 56.82 49.29 53.72 1.84 34.97 46.63 38.81 14.32 54.82 66.87 50.95 60.42 3.87 38.97 50.56 34.93 11.98 22% 18% 18% 12% 125% 32% 29% (10)% (13)% 45.04 56.82 43.32 53.72 1.72 29.48 39.05 38.81 13.84 53.64 37.28 48.80 37.04 4.84 35.28 45.12 24.98 13.52 57.97 48.33 51.57 21% 42.47 47.36 (2.57) 0.96 (0.62) (173)% 0.85 1.44 (14.83) (13.36) (12.60) (3)% (12.99) (12.08) 54.26 53.03 74.36 80.58 46.18 51.26 59.46 61.50 48.49 53.03 66.95 69.09 21% 3% 19% 23% 40.11 51.26 56.24 56.33 45.32 34.98 67.68 68.12 21.09 10.96 16.77 28% 13.07 19.11 1.96 2.93 1.40 2.81 2.98 0.86 2.43 3.11 1.26 16% 26% 42% 2.09 2.46 0.89 2.77 2.66 0.49 Average 0.787 0.750 0.771 2% 0.755 0.782 (1) (2) (3) (4) (5) These benchmark prices are not our realized sales prices. For our average realized sales prices and realized risk management results, refer to the Netbacks tables in the Operating Results, Reportable Segments and Discontinued Operations sections of this MD&A. The average Canadian dollar condensate benchmark price for 2017 was $66.89 per barrel (2016 – $56.25 per barrel; 2015 – $60.56 per barrel); fourth quarter average condensate benchmark price was $73.66 per barrel (2016 – $64.44 per barrel). The average Canadian dollar MSW benchmark price for 2017 was $62.89 per barrel (2016 – $53.13 per barrel; 2015 – $57.95 per barrel); fourth quarter average Canadian dollar MSW benchmark price was $68.95 per barrel (2016 – $61.57 per barrel). The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis. Alberta Energy Company (“AECO”) natural gas. Crude Oil Benchmarks The average Brent, WTI and WCS benchmark prices improved in 2017. Compliance with the production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) led to widespread market expectations of an accelerated return to normal inventory levels. However, without supporting supply and demand drivers, prices continued to be volatile in 2017 as growing supply from the U.S., unstable supply from Libya and Nigeria, severe weather related incidents, and strong global demand resulted in varying expectations on the pace of crude oil and refined product inventory draws. WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. In 2017, WTI benchmark prices weakened relative to Brent compared with 2016 due to growing U.S. crude oil supply and refinery disruptions from hurricanes in the U.S. Gulf Coast resulting in increased crude oil inventories. WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed in 2017 compared with 2016. WCS strengthened relative to WTI due to a temporary decrease in supply of blended heavy oil in Alberta and OPEC’s compliance with production cuts reducing global heavy oil supply. 2017 ANNUAL REPORT | 11 ) l b b / $ S U e g a r e v a ( 65 55 45 35 25 WTI Benchmark Price 2015 2017 2016 Jan Q1 Feb Mar Q2 Apr May June Jul Q3 Aug Sep Oct Q4 Nov Dec ) l b b / $ S U e g a r e v a ( 60 50 40 30 20 10 WCS Benchmark Price 2015 2017 2016 Jan Q1 Feb Mar Apr Q2 May June Jul Q3 Aug Sep Oct Q4 Nov Dec Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our blending ratios in 2017 ranged from approximately 10 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the cost to transport the condensate to Edmonton. The average WTI-Condensate differential changed by US$1.47 per barrel, with condensate being sold at a premium to WTI in 2017 as compared with being sold at a discount in 2016. This change in benchmark pricing resulted from incremental demand for diluent due to a rise in Alberta heavy oil production, and minimal spare capacity on pipelines which increased the cost of transporting condensate to Edmonton. MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production, comparable to the crude oil produced by our Deep Basin Assets. The average MSW benchmark price improved in 2017 compared with 2016, consistent with the general increase in average crude oil benchmark prices. Refining Benchmarks The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 crack spread. The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis. Average Chicago refined product prices increased in 2017 primarily due to strong refined product demand and severe weather related events that impacted the refined product supply output of U.S. Gulf Coast refineries. Average Chicago 3-2-1 crack spreads rose in 2017 compared with 2016 due to the wider Brent-WTI differential reflecting product prices trending with global crude oil prices, significant regional refinery maintenance causing product shortages and strong refined product demand. Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock which is valued on a first in, first out (“FIFO”) accounting basis. RUL Refined Product Price 2015 2017 ) l b b / $ S U e g a r e v a ( 90 80 70 60 50 40 30 2016 Chicago 3-2-1 Crack Spread 2015 2017 2016 ) l b b / $ S U e g a r e v a ( 35 30 25 20 15 10 5 Jan Q1 Feb Mar Apr May Q2 June Jul Aug Q3 Sep Oct Q4 Nov Dec Jan Q1 Feb Mar Apr Q2 May June Jul Q3 Aug Sep Oct Q4 Nov Dec Natural Gas Benchmarks Average AECO and NYMEX natural gas prices rose compared with 2016. Natural gas prices strengthened as North American inventory levels declined due to lower production and stronger demand. Production decreased as a result of reduced drilling programs while demand increased from additional capacity to export North American natural gas to foreign markets. In addition, natural gas prices in 2016 were negatively impacted by an exceptionally warm winter that resulted in poor heating demand and record-high seasonal North American natural gas storage levels. 12 | CENOVUS ENERGY Foreign Exchange Benchmark Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian dollar weakens, our reported results are higher. In addition to our revenues being denominated in U.S. dollars, our long-term debt is also U.S. dollar denominated. In periods of a strengthening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange gains when translated to Canadian dollars. In 2017, the Canadian dollar strengthened relative to the U.S. dollar, which had a negative impact of approximately $360 million on our revenues, excluding our Conventional segment. The Canadian dollar as at December 31, 2017 compared with December 31, 2016 was stronger relative to the U.S. dollar, resulting in $665 million of unrealized foreign exchange gains on the translation of our U.S. dollar debt. FINANCIAL RESULTS Selected Consolidated Financial Results The Acquisition and improvements in commodity prices, as referred to above, were the primary drivers of our financial results in 2017. The following key performance measures are discussed in more detail within this MD&A. ($ millions, except per share amounts) Revenues Operating Margin (1) From Continuing Operations Total Operating Margin Cash From Operating Activities From Continuing Operations Total Cash From Operating Activities Adjusted Funds Flow (2) From Continuing Operations Total Adjusted Funds Flow Operating Earnings (Loss) (2) From Continuing Operations Per Share – Diluted ($) Total Operating Earnings (Loss) Per Share – Diluted ($) Net Earnings (Loss) From Continuing Operations Per Share – Basic and Diluted ($) Total Net Earnings (Loss) Per Share – Basic and Diluted ($) Total Assets Total Long-Term Financial Liabilities (3) Capital Investment (4) From Continuing Operations Total Capital Investment Dividends (5) Cash Dividends Per Share ($) Non-GAAP measure defined in this MD&A. Consolidated Balance Sheets. (1) (2) (3) (4) (5) (34) (0.03) 126 0.11 2017 17,043 2,992 3,483 2,611 3,059 2,447 2,914 2,268 2.06 3,366 3.05 40,933 9,717 1,455 1,661 225 0.20 Percent Change 55% 145% 97% 513% 255% 154% 105% 88% 91% (133)% (124)% (594)% (475)% (718)% (569)% 62% 52% 70% 62% 36% -% 2016 11,006 1,223 1,767 426 861 965 1,423 (291) (0.35) (377) (0.45) (459) (0.55) (545) (0.65) 25,258 6,373 855 1,026 166 0.20 Percent Change (5)% (18)% (28)% (39)% (42)% 8% (16)% (172)% (169)% 6% 8% (150)% (149)% (188)% (187)% (2)% (2)% (42)% (40)% (69)% (77)% 2015 11,529 1,499 2,439 696 1,474 896 1,691 (107) (0.13) (403) (0.49) 914 1.12 618 0.75 25,791 6,552 1,470 1,714 528 0.8524 Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and defined in this MD&A. Includes Long-Term Debt, Risk Management, Contingent Payment Liabilities and other financial liabilities included within Other Liabilities on the Includes expenditures on Property, Plant and Equipment (“PP&E”), E&E assets, and assets held for sale. Dividends issued in shares from treasury for 2017 were $nil (2016 – $nil; 2015 – $182 million). WTI Benchmark Price 2015 2017 WCS Benchmark Price 2015 2017 2016 2016 ) l b b / $ S U e g a r e v a ( 65 55 45 35 25 Jan Q1 Feb Mar Apr May Q2 June Jul Q3 Aug Sep Oct Q4 Nov Dec Jan Q1 Feb Mar Apr Q2 May June Jul Q3 Aug Sep Oct Q4 Nov Dec Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our blending ratios in 2017 ranged from approximately 10 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the cost to transport the condensate to Edmonton. The average WTI-Condensate differential changed by US$1.47 per barrel, with condensate being sold at a premium to WTI in 2017 as compared with being sold at a discount in 2016. This change in benchmark pricing resulted from incremental demand for diluent due to a rise in Alberta heavy oil production, and minimal spare capacity on pipelines which increased the cost of transporting condensate to Edmonton. MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production, comparable to the crude oil produced by our Deep Basin Assets. The average MSW benchmark price improved in 2017 compared with 2016, consistent with the general increase in average crude oil benchmark prices. Refining Benchmarks The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 crack spread. The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis. Average Chicago refined product prices increased in 2017 primarily due to strong refined product demand and severe weather related events that impacted the refined product supply output of U.S. Gulf Coast refineries. Average Chicago 3-2-1 crack spreads rose in 2017 compared with 2016 due to the wider Brent-WTI differential reflecting product prices trending with global crude oil prices, significant regional refinery maintenance causing product shortages and strong refined product demand. Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock which is valued on a first in, first out (“FIFO”) accounting basis. RUL Refined Product Price 2015 ) l b b / $ S U e g a r e v a ( 90 80 70 60 50 40 30 2016 2017 2015 Chicago 3-2-1 Crack Spread 2017 2016 Jan Q1 Feb Mar Apr Q2 May June Jul Aug Q3 Sep Oct Q4 Nov Dec Jan Q1 Feb Mar Apr Q2 May June Jul Q3 Aug Sep Oct Q4 Nov Dec Natural Gas Benchmarks Average AECO and NYMEX natural gas prices rose compared with 2016. Natural gas prices strengthened as North American inventory levels declined due to lower production and stronger demand. Production decreased as a result of reduced drilling programs while demand increased from additional capacity to export North American natural gas to foreign markets. In addition, natural gas prices in 2016 were negatively impacted by an exceptionally warm winter that resulted in poor heating demand and record-high seasonal North American natural gas storage levels. ) l b b / $ S U e g a r e v a ( 60 50 40 30 20 10 ) l b b / $ S U e g a r e v a ( 35 30 25 20 15 10 5 Foreign Exchange Benchmark Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian dollar weakens, our reported results are higher. In addition to our revenues being denominated in U.S. dollars, our long-term debt is also U.S. dollar denominated. In periods of a strengthening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange gains when translated to Canadian dollars. In 2017, the Canadian dollar strengthened relative to the U.S. dollar, which had a negative impact of approximately $360 million on our revenues, excluding our Conventional segment. The Canadian dollar as at December 31, 2017 compared with December 31, 2016 was stronger relative to the U.S. dollar, resulting in $665 million of unrealized foreign exchange gains on the translation of our U.S. dollar debt. FINANCIAL RESULTS Selected Consolidated Financial Results The Acquisition and improvements in commodity prices, as referred to above, were the primary drivers of our financial results in 2017. The following key performance measures are discussed in more detail within this MD&A. ($ millions, except per share amounts) Revenues Operating Margin (1) From Continuing Operations Total Operating Margin Cash From Operating Activities From Continuing Operations Total Cash From Operating Activities Adjusted Funds Flow (2) From Continuing Operations Total Adjusted Funds Flow Operating Earnings (Loss) (2) From Continuing Operations Per Share – Diluted ($) Total Operating Earnings (Loss) Per Share – Diluted ($) Net Earnings (Loss) From Continuing Operations Per Share – Basic and Diluted ($) Total Net Earnings (Loss) Per Share – Basic and Diluted ($) Total Assets Total Long-Term Financial Liabilities (3) Capital Investment (4) From Continuing Operations Total Capital Investment Dividends (5) Cash Dividends Per Share ($) 2017 17,043 2,992 3,483 2,611 3,059 2,447 2,914 Percent Change 55% 145% 97% 513% 255% 154% 105% (34) (0.03) 126 0.11 88% 91% (133)% (124)% 2,268 2.06 3,366 3.05 40,933 9,717 1,455 1,661 225 0.20 (594)% (475)% (718)% (569)% 62% 52% 70% 62% 36% -% 2016 11,006 1,223 1,767 426 861 965 1,423 (291) (0.35) (377) (0.45) (459) (0.55) (545) (0.65) 25,258 6,373 855 1,026 166 0.20 Percent Change (5)% (18)% (28)% (39)% (42)% 8% (16)% (172)% (169)% 6% 8% (150)% (149)% (188)% (187)% (2)% (2)% (42)% (40)% (69)% (77)% 2015 11,529 1,499 2,439 696 1,474 896 1,691 (107) (0.13) (403) (0.49) 914 1.12 618 0.75 25,791 6,552 1,470 1,714 528 0.8524 (1) (2) (3) (4) (5) Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and defined in this MD&A. Non-GAAP measure defined in this MD&A. Includes Long-Term Debt, Risk Management, Contingent Payment Liabilities and other financial liabilities included within Other Liabilities on the Consolidated Balance Sheets. Includes expenditures on Property, Plant and Equipment (“PP&E”), E&E assets, and assets held for sale. Dividends issued in shares from treasury for 2017 were $nil (2016 – $nil; 2015 – $182 million). 2017 ANNUAL REPORT | 13 Revenues ($ millions) Revenues, Comparative Year Increase (Decrease) due to: Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Revenues, End of Year 2017 vs. 2016 2016 vs. 2015 11,006 11,529 4,212 514 1,413 (102) 17,043 (81) - (366) (76) 11,006 These increases in Operating Margin from continuing operations were partially offset by: A rise in transportation and blending expenses primarily due to higher condensate prices along with an increase in condensate volumes required for blending our increased oil sands production; An increase in upstream operating expenses primarily due to the Acquisition and higher fuel costs related to the increase in natural gas consumption; Realized risk management losses of $307 million, compared with gains of $179 million in 2016; and Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), a rise in our liquids sales price and additional sales volumes. Operating Margin From Continuing Operations Variance Upstream revenues from continuing operations increased significantly in 2017 compared with 2016. The rise was primarily related to the Acquisition, incremental sales volumes from our oil sands expansion phases, and higher commodity prices. These increases were partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar and higher royalties. In 2017, Refining and Marketing revenues increased 17 percent compared with 2016. Refining revenues increased primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group increased slightly in 2017 compared with 2016 due to higher crude oil prices and natural gas volumes sold, partially offset by a decline in crude oil volumes and natural gas prices. Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at transfer prices based on current market prices. Further information regarding our revenues can be found in the Reportable Segments section of this MD&A. Year Ended December 31, 2016 Upstream Price Upstream Volumes Upstream Realized Risk Royalties Upstream Operating Refining and Marketing Other (1) Management Expenses Operating Margin Year Ended December 31, 2017 Operating Margin Operating Margin is an additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. ($ millions) Revenues (Add) Deduct: Purchased Product Transportation and Blending Operating Expenses Production and Mineral Taxes Realized (Gain) Loss on Risk Management Activities Operating Margin From Continuing Operations Conventional (Discontinued Operations) Total Operating Margin 2017 17,498 8,476 3,760 1,956 1 313 2,992 491 3,483 2016 11,359 7,325 1,721 1,243 - (153) 1,223 544 1,767 2015 (1) 11,866 7,709 1,816 1,288 1 (447) 1,499 940 2,439 (1) 2015 Operating Margin From Continuing Operations includes $55 million related to certain legacy Conventional royalty interest assets which were sold in 2015 and has been included in the Corporate and Eliminations Segment. • • • • ) s n o i l l i m $ ( 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 1,490 1,223 1,810 486 262 252 683 352 2,992 (1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. Additional details explaining the changes in Operating Margin from continuing operations can be found in the Reportable Segments section of this MD&A. Cash From Operating Activities and Adjusted Funds Flow Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Total Cash From Operating Activities and Adjusted Funds Flow ($ millions) (Add) Deduct: Cash From Operating Activities (1) Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (1) 2017 3,059 (107) 252 2,914 2016 861 (91) (471) 1,423 2015 1,474 (107) (110) 1,691 (1) Includes results from our Conventional segment, which has been classified as a discontinued operation. Cash From Operating Activities and Adjusted Funds Flow increased compared with 2016 due to a higher Operating Margin, as discussed above, and a realized risk management gain on foreign exchange contracts due to hedging activity undertaken to support the Acquisition. These increases were partially offset by a rise in finance costs primarily associated with additional debt incurred to finance the Acquisition and an increase in realized foreign exchange losses on working capital items. The change in non-cash working capital in 2017 was primarily due to a decrease in accounts receivable and inventory, partially offset by higher income tax receivable and a decrease in accounts payable. For 2016, the change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory, partially offset by an increase in accounts payable. m $ ( ) s n o i l l i 2,500 2,000 1,500 1,000 500 0 Operating Margin From Continuing Operations by Segment 2,187 1,059 877 598 346 385 207 - - Oil Sands Deep Basin Refining and Marketing 2017 2016 2015 Operating Margin from continuing operations increased significantly in 2017 compared with 2016 primarily due to: • • • Increased sales volumes; Higher average liquids sales prices; and A higher Operating Margin from Refining and Marketing. 14 | CENOVUS ENERGY • • • These increases in Operating Margin from continuing operations were partially offset by: • A rise in transportation and blending expenses primarily due to higher condensate prices along with an increase in condensate volumes required for blending our increased oil sands production; An increase in upstream operating expenses primarily due to the Acquisition and higher fuel costs related to the increase in natural gas consumption; Realized risk management losses of $307 million, compared with gains of $179 million in 2016; and Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), a rise in our liquids sales price and additional sales volumes. Revenues ($ millions) Revenues, Comparative Year Increase (Decrease) due to: Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Revenues, End of Year 2017 vs. 2016 2016 vs. 2015 11,006 11,529 4,212 514 1,413 (102) 17,043 (81) - (366) (76) 11,006 Upstream revenues from continuing operations increased significantly in 2017 compared with 2016. The rise was primarily related to the Acquisition, incremental sales volumes from our oil sands expansion phases, and higher commodity prices. These increases were partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar and higher royalties. In 2017, Refining and Marketing revenues increased 17 percent compared with 2016. Refining revenues increased primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group increased slightly in 2017 compared with 2016 due to higher crude oil prices and natural gas volumes sold, partially offset by a decline in crude oil volumes and natural gas prices. Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at transfer prices based on current market prices. Operating Margin Operating Margin is an additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. ($ millions) Revenues (Add) Deduct: Purchased Product Transportation and Blending Operating Expenses Production and Mineral Taxes Realized (Gain) Loss on Risk Management Activities Operating Margin From Continuing Operations Conventional (Discontinued Operations) Total Operating Margin 2017 17,498 8,476 3,760 1,956 1 313 2,992 491 3,483 2016 11,359 7,325 1,721 1,243 - (153) 1,223 544 1,767 2015 (1) 11,866 7,709 1,816 1,288 1 (447) 1,499 940 2,439 (1) 2015 Operating Margin From Continuing Operations includes $55 million related to certain legacy Conventional royalty interest assets which were sold in 2015 and has been included in the Corporate and Eliminations Segment. Operating Margin from continuing operations increased significantly in 2017 compared with 2016 Operating Margin From Continuing Operations by Segment primarily due to: Increased sales volumes; • • • Higher average liquids sales prices; and A higher Operating Margin from Refining and Marketing. 2,187 1,059 877 2,500 2,000 1,500 1,000 ) s n o i l l i m $ ( 500 0 598 346 385 Oil Sands Deep Basin Refining and Marketing 207 - - 2017 2016 2015 Further information regarding our revenues can be found in the Reportable Segments section of this MD&A. Year Ended December 31, 2016 Upstream Price Upstream Volumes Upstream Realized Risk Management Royalties Upstream Operating Expenses Refining and Marketing Operating Margin Other (1) Year Ended December 31, 2017 Operating Margin From Continuing Operations Variance 1,810 486 262 252 683 352 2,992 ) s n o i l l i m $ ( 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 1,490 1,223 (1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. Additional details explaining the changes in Operating Margin from continuing operations can be found in the Reportable Segments section of this MD&A. Cash From Operating Activities and Adjusted Funds Flow Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Total Cash From Operating Activities and Adjusted Funds Flow ($ millions) Cash From Operating Activities (1) (Add) Deduct: Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (1) 2017 3,059 (107) 252 2,914 2016 861 (91) (471) 1,423 2015 1,474 (107) (110) 1,691 (1) Includes results from our Conventional segment, which has been classified as a discontinued operation. Cash From Operating Activities and Adjusted Funds Flow increased compared with 2016 due to a higher Operating Margin, as discussed above, and a realized risk management gain on foreign exchange contracts due to hedging activity undertaken to support the Acquisition. These increases were partially offset by a rise in finance costs primarily associated with additional debt incurred to finance the Acquisition and an increase in realized foreign exchange losses on working capital items. The change in non-cash working capital in 2017 was primarily due to a decrease in accounts receivable and inventory, partially offset by higher income tax receivable and a decrease in accounts payable. For 2016, the change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory, partially offset by an increase in accounts payable. 2017 ANNUAL REPORT | 15 Operating Earnings (Loss) Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis. ($ millions) Earnings (Loss) From Continuing Operations, Before Income Tax Add (Deduct): Unrealized Risk Management (Gain) Loss (1) Non-Operating Unrealized Foreign Exchange (Gain) Loss (2) Revaluation (Gain) (Gain) Loss on Divestiture of Assets Operating Earnings (Loss) From Continuing Operations, Before Income Tax Income Tax Expense (Recovery) Operating Earnings (Loss) From Continuing Operations Operating Earnings (Loss) From Discontinued Operations Total Operating Earnings (Loss) 2017 2,216 729 (651) (2,555) 1 (260) (226) (34) 160 126 2016 (802) 554 (196) - 6 (438) (147) (291) (86) (377) 2015 890 195 1,064 - (2,392) (243) (136) (107) (296) (403) (1) (2) Includes the reversal of unrealized (gains) losses recorded in prior periods. Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange (gains) losses on settlement of intercompany transactions. Operating Earnings from continuing operations increased in 2017 compared with 2016 primarily due to higher cash from operating activities and Adjusted Funds Flow, as discussed above, greater unrealized foreign exchange gains on operating items compared with losses in 2016, and the re-measurement of the contingent payment, partially offset by an increase in depreciation, depletion and amortization (“DD&A”) and exploration expense due to asset writedowns. Net Earnings (Loss) ($ millions) Net Earnings (Loss) From Continuing Operations, Comparative Year Increase (Decrease) due to: Operating Margin From Continuing Operations Corporate and Eliminations: Unrealized Risk Management Gain (Loss) Unrealized Foreign Exchange Gain (Loss) Revaluation Gain Re-measurement of Contingent Payment Gain (Loss) on Divestiture of Assets Expenses (1) DD&A Exploration Expense Income Tax Recovery (Expense) Net Earnings (Loss) From Continuing Operations 2017 vs. 2016 2016 vs. 2015 (459) 1,769 (175) 668 2,555 138 5 (149) (907) (886) (291) 2,268 914 (276) (359) 1,286 - - (2,398) (72) 62 65 319 (459) (1) Includes realized risk management (gains) losses, general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, transaction costs, research costs, other (income) loss, net and Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses. Net Earnings from continuing operations in 2017 increased due to: • • • The revaluation gain of $2,555 million related to the deemed disposition of our pre-existing interest in FCCL; Non-operating unrealized foreign exchange gains of $651 million compared with $196 million in 2016; and Higher Operating Earnings, as discussed above. These increases were partially offset by a deferred income tax expense in 2017. The gain on the revaluation of our pre-existing interest in FCCL resulted in a deferred tax expense, which was partially offset by a recovery due to the reduction of the U.S. federal corporate income tax rate. In 2016, a deferred tax recovery was recorded largely due to risk management losses and the recognition of operating losses. Net Earnings from discontinued operations in 2017 was $1,098 million, including an after-tax gain of $938 million on the divestiture of the Conventional segment assets. In 2016, discontinued operations generated a net loss of $86 million. 16 | CENOVUS ENERGY Net Capital Investment ($ millions) Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Capital Investment – Continuing Operations Conventional (Discontinued Operations) Total Capital Investment Acquisitions (1) Divestitures (1) Net Capital Investment (2) 2017 973 225 180 77 1,455 206 1,661 18,388 (3,210) 16,839 2016 604 - 220 31 855 171 1,026 11 (8) 1,029 2015 1,185 - 248 37 1,470 244 1,714 87 (3,344) (1,543) (1) In connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS 3 “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017. (2) Includes expenditures on PP&E, E&E assets and assets held for sale. Capital investment in continuing operations in 2017 increased $600 million compared with 2016, reflecting our increased ownership in FCCL through the Acquisition. Oil Sands capital investment focused on sustaining capital related to existing production; Christina Lake expansion phase G; and stratigraphic test wells to determine pad placement for sustaining wells, near-term expansion phases, and progression of certain emerging assets. Deep Basin capital investment related to asset development planning and our horizontal drilling and completion program targeting liquids-rich natural gas within the Deep Basin corridor. Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A. Capital Investment Decisions We have now completed the divestiture of our legacy Conventional assets. However, we continue to focus on deleveraging our balance sheet and are currently marketing for sale certain non-core Deep Basin Assets in order to further streamline our portfolio. In addition to our commitment to continue reducing our debt, we are actively identifying further cost reduction opportunities. Once our balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner: First, to sustaining and maintenance capital for our existing business operations; Second, to paying our current dividend as part of providing strong total shareholder return; and Third, for growth or discretionary capital. • • • Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information. ($ millions) Adjusted Funds Flow (1) Total Capital Investment (1) Free Funds Flow (1) (2) Cash Dividends 2017 2,914 1,661 1,253 225 1,028 2016 1,423 1,026 397 166 231 2015 1,691 1,714 (23) 528 (551) (1) (2) Includes our Conventional segment, which has been classified as a discontinued operation. Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment. We expect our capital investment and cash dividends for 2018 to be funded from our internally generated cash flows and our cash balance on hand. Operating Earnings (Loss) Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis. ($ millions) Add (Deduct): Earnings (Loss) From Continuing Operations, Before Income Tax Unrealized Risk Management (Gain) Loss (1) Non-Operating Unrealized Foreign Exchange (Gain) Loss (2) Operating Earnings (Loss) From Continuing Operations, Revaluation (Gain) (Gain) Loss on Divestiture of Assets Before Income Tax Income Tax Expense (Recovery) Operating Earnings (Loss) From Continuing Operations Operating Earnings (Loss) From Discontinued Operations Total Operating Earnings (Loss) 2017 2,216 729 (651) (2,555) 1 (260) (226) (34) 160 126 Includes the reversal of unrealized (gains) losses recorded in prior periods. (1) (2) Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange (gains) losses on settlement of intercompany transactions. Operating Earnings from continuing operations increased in 2017 compared with 2016 primarily due to higher cash from operating activities and Adjusted Funds Flow, as discussed above, greater unrealized foreign exchange gains on operating items compared with losses in 2016, and the re-measurement of the contingent payment, partially offset by an increase in depreciation, depletion and amortization (“DD&A”) and exploration expense due to asset Net Earnings (Loss) From Continuing Operations, Comparative Year 2017 vs. 2016 2016 vs. 2015 writedowns. Net Earnings (Loss) ($ millions) Increase (Decrease) due to: Operating Margin From Continuing Operations Corporate and Eliminations: Unrealized Risk Management Gain (Loss) Unrealized Foreign Exchange Gain (Loss) Revaluation Gain Re-measurement of Contingent Payment Gain (Loss) on Divestiture of Assets Expenses (1) DD&A Exploration Expense Income Tax Recovery (Expense) Net Earnings (Loss) From Continuing Operations 2016 (802) 554 (196) - 6 (438) (147) (291) (86) (377) (459) 1,769 (175) 668 2,555 138 5 (149) (907) (886) (291) 2,268 2015 890 195 1,064 - (2,392) (243) (136) (107) (296) (403) 914 (276) (359) 1,286 - - (2,398) (72) 62 65 319 (459) (1) Includes realized risk management (gains) losses, general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, transaction costs, research costs, other (income) loss, net and Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses. Net Earnings from continuing operations in 2017 increased due to: The revaluation gain of $2,555 million related to the deemed disposition of our pre-existing interest in FCCL; Non-operating unrealized foreign exchange gains of $651 million compared with $196 million in 2016; and Higher Operating Earnings, as discussed above. • • • These increases were partially offset by a deferred income tax expense in 2017. The gain on the revaluation of our pre-existing interest in FCCL resulted in a deferred tax expense, which was partially offset by a recovery due to the reduction of the U.S. federal corporate income tax rate. In 2016, a deferred tax recovery was recorded largely due to risk management losses and the recognition of operating losses. Net Earnings from discontinued operations in 2017 was $1,098 million, including an after-tax gain of $938 million on the divestiture of the Conventional segment assets. In 2016, discontinued operations generated a net loss of $86 million. Net Capital Investment ($ millions) Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Capital Investment – Continuing Operations Conventional (Discontinued Operations) Total Capital Investment Acquisitions (1) Divestitures (1) Net Capital Investment (2) 2017 973 225 180 77 1,455 206 1,661 18,388 (3,210) 16,839 2016 604 - 220 31 855 171 1,026 11 (8) 1,029 2015 1,185 - 248 37 1,470 244 1,714 87 (3,344) (1,543) (1) (2) In connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS 3 “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017. Includes expenditures on PP&E, E&E assets and assets held for sale. Capital investment in continuing operations in 2017 increased $600 million compared with 2016, reflecting our increased ownership in FCCL through the Acquisition. Oil Sands capital investment focused on sustaining capital related to existing production; Christina Lake expansion phase G; and stratigraphic test wells to determine pad placement for sustaining wells, near-term expansion phases, and progression of certain emerging assets. Deep Basin capital investment related to asset development planning and our horizontal drilling and completion program targeting liquids-rich natural gas within the Deep Basin corridor. Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A. Capital Investment Decisions We have now completed the divestiture of our legacy Conventional assets. However, we continue to focus on deleveraging our balance sheet and are currently marketing for sale certain non-core Deep Basin Assets in order to further streamline our portfolio. In addition to our commitment to continue reducing our debt, we are actively identifying further cost reduction opportunities. Once our balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner: • • • First, to sustaining and maintenance capital for our existing business operations; Second, to paying our current dividend as part of providing strong total shareholder return; and Third, for growth or discretionary capital. Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information. ($ millions) Adjusted Funds Flow (1) Total Capital Investment (1) Free Funds Flow (1) (2) Cash Dividends 2017 2,914 1,661 1,253 225 1,028 2016 1,423 1,026 397 166 231 2015 1,691 1,714 (23) 528 (551) (1) (2) Includes our Conventional segment, which has been classified as a discontinued operation. Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment. We expect our capital investment and cash dividends for 2018 to be funded from our internally generated cash flows and our cash balance on hand. 2017 ANNUAL REPORT | 17 REPORTABLE SEGMENTS Our reportable segments are as follows: Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. Our interest in certain of our operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake increased from 50 percent to 100 percent on May 17, 2017. Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and natural gas liquids. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17, 2017. Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, a owns crude-by-rail terminal in Alberta. This segment coordinates and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. marketing Cenovus’s operates Cenovus and Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. In 2017, Cenovus divested the majority of the crude oil and natural gas assets in the Company’s Conventional segment. As such, the results of operations have been presented as a discontinued operation and all prior periods restated. This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018. Refer to the Discontinued Operations section of this MD&A for more information. Revenues by Reportable Segment ($ millions) Oil Sands (1) Deep Basin (2) Refining and Marketing Corporate and Eliminations 2017 7,132 514 9,852 (455) 17,043 2016 2,920 - 8,439 (353) 11,006 2015 3,001 - 8,805 (277) 11,529 (1) (2) Our 2017 results include 229 days of FCCL operations at 100 percent. See the Oil Sands segment section of this MD&A for more details. Our 2017 results include 229 days of operations from the Deep Basin Assets. See the Deep Basin segment section of this MD&A for more details. 18 | CENOVUS ENERGY OIL SANDS • • • of 2016; barrel); and Oil Sands – Crude Oil Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses ) s n o i l l i m $ ( 6,000 5,000 4,000 3,000 2,000 1,000 0 875 Revenues Price In northeastern Alberta, we own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects following the completion of the Acquisition. In addition, we have several emerging projects in the early stages of development. The Oil Sands segment includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations. Significant developments in our Oil Sands segment in 2017 compared with 2016 include: Increasing our crude oil production by 95 percent primarily due to the Acquisition and incremental production volumes from Christina Lake phase F and Foster Creek phase G, both of which started up in the second half Crude oil netbacks, excluding realized risk management activities, of $24.54 per barrel (2016 – $11.94 per Generating Operating Margin net of capital investment of $1,214 million, an increase of $941 million. 2017 7,340 230 7,110 3,704 868 307 2,231 969 1,262 2016 2,911 9 2,902 1,720 486 (179) 875 601 274 2015 3,000 29 2,971 1,814 511 (400) 1,046 1,184 (138) Transportation and Blending Operating (Gain) Loss on Risk Management Operating Margin Capital Investment Operating Margin Variance Operating Margin Net of Related Capital Investment 1,648 486 221 1,350 1,431 1,984 382 2,231 Year Ended Price (1) Volume December 31, 2016 Condensate Revenue (1) Realized Risk Management Royalties Transportation Operating Expenses Year Ended and Blending (1) December 31, 2017 (1) Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. In 2017, our average crude oil sales price increased to $41.49 per barrel (2016 – $27.64 per barrel). The rise in our crude oil price was consistent with the increase in the WCS and Christina Dilbit Blend (“CDB”) benchmark prices and the narrowing of the WCS-Condensate differential, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. The WCS-CDB differential narrowed to a discount of US$1.67 per barrel (2016 - discount of US$2.05 per barrel). Our crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios range between 25 percent and 33 percent. As the cost of condensate increases relative to the price of blended crude oil, our bitumen sales price decreases. Due to high demand for condensate at Edmonton, we also purchase condensate from U.S. markets. As such, our average cost of condensate is generally higher than the Edmonton benchmark price due to transportation between market hubs and transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to when we blend it with our production. In a rising price environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a lower price earlier in the year. REPORTABLE SEGMENTS Our reportable segments are as follows: Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. Our interest in certain of our operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake increased from 50 percent to 100 percent on May 17, 2017. Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and natural gas liquids. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17, 2017. Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. In 2017, Cenovus divested the majority of the crude oil and natural gas assets in the Company’s Conventional segment. As such, the results of operations have been presented as a discontinued operation and all prior periods restated. This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018. Refer to the Discontinued Operations section of this MD&A for more information. Revenues by Reportable Segment ($ millions) Oil Sands (1) Deep Basin (2) Refining and Marketing Corporate and Eliminations 2017 7,132 514 9,852 (455) 17,043 2016 2,920 - 8,439 (353) 2015 3,001 - 8,805 (277) 11,006 11,529 (1) (2) Our 2017 results include 229 days of FCCL operations at 100 percent. See the Oil Sands segment section of this MD&A for more details. Our 2017 results include 229 days of operations from the Deep Basin Assets. See the Deep Basin segment section of this MD&A for more details. OIL SANDS In northeastern Alberta, we own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects following the completion of the Acquisition. In addition, we have several emerging projects in the early stages of development. The Oil Sands segment includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations. Significant developments in our Oil Sands segment in 2017 compared with 2016 include: • Increasing our crude oil production by 95 percent primarily due to the Acquisition and incremental production volumes from Christina Lake phase F and Foster Creek phase G, both of which started up in the second half of 2016; Crude oil netbacks, excluding realized risk management activities, of $24.54 per barrel (2016 – $11.94 per barrel); and Generating Operating Margin net of capital investment of $1,214 million, an increase of $941 million. • • Oil Sands – Crude Oil Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses Transportation and Blending Operating (Gain) Loss on Risk Management Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Operating Margin Variance 2017 7,340 230 7,110 3,704 868 307 2,231 969 1,262 2016 2,911 9 2,902 1,720 486 (179) 875 601 274 2015 3,000 29 2,971 1,814 511 (400) 1,046 1,184 (138) ) s n o i l l i m $ ( 6,000 5,000 4,000 3,000 2,000 1,000 0 875 1,648 486 221 1,350 1,431 1,984 382 2,231 Year Ended December 31, 2016 Price (1) Volume Condensate Revenue (1) Realized Risk Management Royalties Transportation and Blending (1) Operating Expenses Year Ended December 31, 2017 (1) Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. Revenues Price In 2017, our average crude oil sales price increased to $41.49 per barrel (2016 – $27.64 per barrel). The rise in our crude oil price was consistent with the increase in the WCS and Christina Dilbit Blend (“CDB”) benchmark prices and the narrowing of the WCS-Condensate differential, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. The WCS-CDB differential narrowed to a discount of US$1.67 per barrel (2016 - discount of US$2.05 per barrel). Our crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios range between 25 percent and 33 percent. As the cost of condensate increases relative to the price of blended crude oil, our bitumen sales price decreases. Due to high demand for condensate at Edmonton, we also purchase condensate from U.S. markets. As such, our average cost of condensate is generally higher than the Edmonton benchmark price due to transportation between market hubs and transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to when we blend it with our production. In a rising price environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a lower price earlier in the year. 2017 ANNUAL REPORT | 19 Production Volumes (barrels per day) Foster Creek Christina Lake 2017 124,752 167,727 292,479 Percent Change 78% 111% 95% 2016 70,244 79,449 149,693 Percent Change 7% 6% 7% 2015 65,345 74,975 140,320 In 2017, production increased primarily due to incremental volumes at Foster Creek and Christina Lake of 48,080 barrels per day and 64,437 barrels per day, respectively, as a result of the Acquisition. The phase G expansion at Foster Creek and the phase F expansion at Christina Lake also contributed to higher volumes. Production at Foster Creek was reduced as a result of temporary treating issues and a 20-day planned turnaround completed in 2017. Condensate The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the WCS-Condensate differential during 2017, the proportion of the cost of condensate recovered increased. The total amount of condensate used increased as a result of higher production volumes. Royalties Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price. Royalty calculations differ between properties. Royalties at Foster Creek, a post-payout project, are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and sales prices. Net profits are a function of sales volumes, sales prices and allowed operating and capital costs. Royalties at Christina Lake, a pre-payout project, are based on a monthly calculation that applies a royalty rate (ranging from one to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project. Effective Royalty Rates (percent) Foster Creek Christina Lake 2017 11.4 2.5 2016 - 1.6 2015 1.9 2.8 Royalties increased $221 million in 2017 compared with 2016. Royalties at Foster Creek increased primarily due to a higher WTI benchmark price (which determines the royalty rate). The royalty calculation was based on net profits as compared with a calculation based on gross revenues for 2016, resulting in a significant increase in the royalty rate. In 2016, the low royalty rate was primarily due to low crude oil sales prices, a decline in the WTI benchmark price and a true-up of the 2015 royalty calculation. Christina Lake royalties increased in 2017 primarily as a result of a rise in the WTI benchmark price (which determines the royalty rate) and higher crude oil sales prices. Expenses Transportation and Blending Transportation and blending costs increased $1,984 million. Blending costs increased due to a rise in condensate volumes required for our increased production as well as higher condensate prices. Our condensate costs were higher than the average Edmonton benchmark price, primarily due to the transportation expense associated with moving the condensate between market hubs and to our oil sands projects. Transportation costs increased primarily due to incremental sales volumes as a result of the Acquisition and expansion phases. In addition, rail costs rose as a result of moving higher volumes by rail over longer distances to U.S. markets. We transported an average of 9,743 barrels per day of crude oil by rail (2016 – 4,906 barrels per day). 20 | CENOVUS ENERGY Per-unit Transportation Expenses At both Foster Creek and Christina Lake, per-barrel transportation costs declined primarily due to lower pipeline tariffs from an increase in the proportion of Canadian sales in 2017. Foster Creek per-barrel transportation costs were partially offset by higher rail costs from additional volumes shipped to the U.S. by unit trains. Primary drivers of our operating expenses in 2017 were workforce costs, fuel, repairs and maintenance, chemical costs and workovers. While unit operating costs decreased six percent, total operating expenses increased $382 million primarily due to the Acquisition, higher fuel costs due to increased fuel consumption, additional repairs and maintenance, as well as increased chemical and workforce costs associated with the phase F expansion at Christina Lake. In addition, repairs and maintenance costs, as well as fluid, waste handling and trucking costs increased in 2017 due to the 20-day turnaround at Foster Creek. Per-unit Operating Expenses 2017 2.44 8.02 10.46 2.06 4.78 6.84 8.40 Percent Change (1)% (1)% (1)% (1)% (11)% (9)% (6)% 2016 2.46 8.09 10.55 2.08 5.40 7.48 8.91 Percent Change (12)% (17)% (16)% (5)% (7)% (7)% (12)% 2015 2.80 9.80 12.60 2.20 5.81 8.01 10.13 Operating ($/bbl) Foster Creek Christina Lake Fuel Non-fuel Total Fuel Non-fuel Total Total At Foster Creek, per-barrel fuel costs decreased slightly due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses declined in 2017 primarily due to higher production, partially offset by higher repairs and maintenance, an increase in workover costs due to increased pump changes, higher chemical costs, as well as increased fluid, waste handling and trucking costs due to the 20-day planned turnaround in the second quarter. This represents the largest scale turnaround executed to date and it was completed under budget. At Christina Lake, fuel costs declined on a per-barrel basis due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses decreased primarily due to higher production, partially offset by increased workforce and chemical costs associated with the phase F expansion, as well as higher repairs and maintenance activities. Netbacks (1) ($/bbl) Sales Price Royalties Transportation and Blending Operating Expenses Netback Excluding Realized Risk Management Realized Risk Management Gain (Loss) Netback Including Realized Risk Management Risk Management Oil Sands – Natural Gas Foster Creek Christina Lake 2017 43.75 4.00 8.73 10.46 20.56 (2.95) 2016 30.32 (0.01) 8.84 10.55 10.94 3.51 2015 33.65 0.47 8.84 12.60 11.74 8.60 2017 39.78 0.87 4.52 6.84 27.55 (2.99) 2016 25.30 0.33 4.68 7.48 12.81 3.08 2015 28.45 0.67 4.72 8.01 15.05 7.33 17.61 14.45 20.34 24.56 15.89 22.38 (1) Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Risk management activities in 2017 resulted in realized losses of $307 million (2016 – realized gains of $179 million), consistent with average benchmark prices exceeding our contract prices. Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production in 2017, net of internal usage, was 10 MMcf per day (2016 – 17 MMcf per day). Operating Margin was $1 million in 2017 (2016 – $4 million), decreasing as a result of lower natural gas volumes, partially offset by higher natural gas sales prices. Production Volumes (barrels per day) Foster Creek Christina Lake completed in 2017. Condensate 2017 124,752 167,727 292,479 Percent Change 78% 111% 95% 2016 70,244 79,449 149,693 Percent Change 7% 6% 7% 2015 65,345 74,975 140,320 In 2017, production increased primarily due to incremental volumes at Foster Creek and Christina Lake of 48,080 barrels per day and 64,437 barrels per day, respectively, as a result of the Acquisition. The phase G expansion at Foster Creek and the phase F expansion at Christina Lake also contributed to higher volumes. Production at Foster Creek was reduced as a result of temporary treating issues and a 20-day planned turnaround The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the WCS-Condensate differential during 2017, the proportion of the cost of condensate recovered increased. The total amount of condensate used increased as a result of higher production volumes. Royalties Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price. Royalty calculations differ between properties. Royalties at Foster Creek, a post-payout project, are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and sales prices. Net profits are a function of sales volumes, sales prices and allowed operating Royalties at Christina Lake, a pre-payout project, are based on a monthly calculation that applies a royalty rate (ranging from one to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross 2017 11.4 2.5 2016 - 1.6 2015 1.9 2.8 Royalties increased $221 million in 2017 compared with 2016. Royalties at Foster Creek increased primarily due to a higher WTI benchmark price (which determines the royalty rate). The royalty calculation was based on net profits as compared with a calculation based on gross revenues for 2016, resulting in a significant increase in the royalty rate. In 2016, the low royalty rate was primarily due to low crude oil sales prices, a decline in the WTI benchmark price and a true-up of the 2015 royalty calculation. Christina Lake royalties increased in 2017 primarily as a result of a rise in the WTI benchmark price (which determines the royalty rate) and higher crude oil sales prices. and capital costs. revenues from the project. Effective Royalty Rates (percent) Foster Creek Christina Lake Expenses Transportation and Blending Transportation and blending costs increased $1,984 million. Blending costs increased due to a rise in condensate volumes required for our increased production as well as higher condensate prices. Our condensate costs were higher than the average Edmonton benchmark price, primarily due to the transportation expense associated with moving the condensate between market hubs and to our oil sands projects. Transportation costs increased primarily due to incremental sales volumes as a result of the Acquisition and expansion phases. In addition, rail costs rose as a result of moving higher volumes by rail over longer distances to U.S. markets. We transported an average of 9,743 barrels per day of crude oil by rail (2016 – 4,906 barrels per day). Per-unit Transportation Expenses At both Foster Creek and Christina Lake, per-barrel transportation costs declined primarily due to lower pipeline tariffs from an increase in the proportion of Canadian sales in 2017. Foster Creek per-barrel transportation costs were partially offset by higher rail costs from additional volumes shipped to the U.S. by unit trains. Operating Primary drivers of our operating expenses in 2017 were workforce costs, fuel, repairs and maintenance, chemical costs and workovers. While unit operating costs decreased six percent, total operating expenses increased $382 million primarily due to the Acquisition, higher fuel costs due to increased fuel consumption, additional repairs and maintenance, as well as increased chemical and workforce costs associated with the phase F expansion at Christina Lake. In addition, repairs and maintenance costs, as well as fluid, waste handling and trucking costs increased in 2017 due to the 20-day turnaround at Foster Creek. Per-unit Operating Expenses ($/bbl) Foster Creek Fuel Non-fuel Total Christina Lake Fuel Non-fuel Total Total 2017 2.44 8.02 10.46 2.06 4.78 6.84 8.40 Percent Change (1)% (1)% (1)% (1)% (11)% (9)% (6)% 2016 2.46 8.09 10.55 2.08 5.40 7.48 8.91 Percent Change (12)% (17)% (16)% (5)% (7)% (7)% (12)% 2015 2.80 9.80 12.60 2.20 5.81 8.01 10.13 At Foster Creek, per-barrel fuel costs decreased slightly due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses declined in 2017 primarily due to higher production, partially offset by higher repairs and maintenance, an increase in workover costs due to increased pump changes, higher chemical costs, as well as increased fluid, waste handling and trucking costs due to the 20-day planned turnaround in the second quarter. This represents the largest scale turnaround executed to date and it was completed under budget. At Christina Lake, fuel costs declined on a per-barrel basis due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses decreased primarily due to higher production, partially offset by increased workforce and chemical costs associated with the phase F expansion, as well as higher repairs and maintenance activities. Netbacks (1) ($/bbl) Sales Price Royalties Transportation and Blending Operating Expenses Netback Excluding Realized Risk Management Realized Risk Management Gain (Loss) Netback Including Realized Risk Management Foster Creek Christina Lake 2017 43.75 4.00 8.73 10.46 20.56 (2.95) 2016 30.32 (0.01) 8.84 10.55 10.94 3.51 2015 33.65 0.47 8.84 12.60 11.74 8.60 2017 39.78 0.87 4.52 6.84 27.55 (2.99) 2016 25.30 0.33 4.68 7.48 12.81 3.08 2015 28.45 0.67 4.72 8.01 15.05 7.33 17.61 14.45 20.34 24.56 15.89 22.38 (1) Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Risk Management Risk management activities in 2017 resulted in realized losses of $307 million (2016 – realized gains of $179 million), consistent with average benchmark prices exceeding our contract prices. Oil Sands – Natural Gas Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production in 2017, net of internal usage, was 10 MMcf per day (2016 – 17 MMcf per day). Operating Margin was $1 million in 2017 (2016 – $4 million), decreasing as a result of lower natural gas volumes, partially offset by higher natural gas sales prices. 2017 ANNUAL REPORT | 21 Oil Sands – Capital Investment DD&A ($ millions) Foster Creek Christina Lake Narrows Lake Telephone Lake Grand Rapids (1) Other (2) Capital Investment (3) 2017 2016 455 426 881 12 34 1 45 973 263 282 545 7 16 6 30 604 2015 403 647 1,050 47 24 38 26 1,185 (1) (2) (3) Grand Rapids asset was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017. Includes new resource plays and Athabasca natural gas. Includes expenditures on PP&E, E&E assets and assets held for sale. Existing Projects Capital investment in 2017 increased by $369 million from 2016, reflecting our 100 percent ownership of FCCL as of May 17, 2017. At Foster Creek, capital investment in 2017 was focused on sustaining capital related to existing production and stratigraphic test wells. In 2016, capital investment included sustaining capital related to existing production and stratigraphic test wells, as well as capital associated with the completion of phase G. In 2017, Christina Lake capital investment focused on sustaining capital related to existing production, the phase G expansion and stratigraphic test wells. In 2016, capital was focused on sustaining capital related to existing production, the completion of expansion phase F and stratigraphic test wells. Capital investment at Narrows Lake in 2017 and 2016 primarily related to drilling of stratigraphic test wells to further progress the project, as well as preservation of equipment at site. Emerging Projects In 2017, Telephone Lake capital investment concentrated on drilling stratigraphic test wells to further assess the project. In 2016, spending was reduced in response to the low commodity price environment and focused on front-end engineering work for the central processing facility. segment. DEEP BASIN Drilling Activity Foster Creek Christina Lake Narrows Lake Telephone Lake Other (2) Gross Stratigraphic Test Wells 2017 2016 2015 Gross Production Wells (1) 2016 2017 2015 96 108 204 2 13 1 220 95 104 199 1 - 5 205 124 40 164 - - - 164 41 25 66 - - - 66 18 35 53 - - 1 54 28 67 95 - - 1 96 (1) (2) SAGD well pairs are counted as a single producing well. Includes Grand Rapids which was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017. Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and near-term expansion phases and to further progress the evaluation of emerging assets. Future Capital Investment Foster Creek is currently producing from phases A through G. Capital investment for 2018 is forecast to be between $500 million and $550 million. We plan to continue focusing on sustaining capital related to existing production. Christina Lake is producing from phases A through F. Capital investment for 2018 is forecast to be between $500 million and $550 million, focused on sustaining capital and construction of the phase G expansion. Field construction of phase G, which has an initial design capacity of 50,000 barrels per day, is progressing well and remains on track. Phase G is expected to start producing in the second half of 2019. Capital investment at Narrows Lake in 2018 is forecast to be between $5 million and $10 million and will focus primarily on equipment preservation related to the suspension of construction at Narrows Lake. In 2018, our Technology and other capital, forecast to be between $35 million and $45 million, relates to technology development initiatives and annual environmental and regulatory commitments. Our 2018 Oil Sands capital investment is forecast to be between $1,040 million and $1,155 million. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. 22 | CENOVUS ENERGY We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. In 2017, Oil Sands DD&A increased $575 million primarily due to higher sales volumes as a result of the Acquisition. The average depletion rate was approximately $11.50 per barrel compared with $11.30 per barrel in 2016. Our DD&A rate increased primarily due to an increase in the carrying value of our assets as a result of the re-measurement of our pre-existing interest in FCCL and the acquisition of the additional 50 percent interest of FCCL, which was partially offset by proved reserve additions. Future development costs declined due to cost savings at both Foster Creek and Christina Lake related to a reduction in per well costs and increased well pair spacing. This decline was partially offset by an increase in costs related to the expansion of the development area and inclusion of phase G costs at Christina Lake. Exploration Expense For the year ended December 31, 2017, Management has determined that costs incurred to date on certain E&E assets, primarily in the Greater Borealis area, were not recoverable. As a result, $888 million of previously capitalized costs were recorded as exploration expense. In 2016, exploration expense was $2 million. Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects. These assets reside primarily in the Borealis cash-generating unit (“CGU”) within the Oil Sands On May 17, 2017, we acquired the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets including undeveloped land, exploration and production assets, and related infrastructure in Alberta and British Columbia. Our Deep Basin Assets include approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average working interest of 70 percent. In addition, the Deep Basin Assets include interests in numerous natural gas processing plants with an estimated net processing capacity of 1.4 Bcf per day. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement our long-term oil sands development. We have now successfully integrated the Deep Basin Assets, maintained business continuity and continue to deliver safe and reliable operations. Significant developments in our Deep Basin segment in 2017 include: Successful integration of the Deep Basin Assets; • • • • • Total capital investment of $225 million related to the drilling of 28 horizontal production wells targeting liquids rich natural gas, the completion of 20 wells, and bringing 14 wells on production; Total production from the date of the Acquisition averaging 117,138 BOE per day, equivalent to 73,492 BOE Netback of $7.32 per BOE; per day for the year; and Generating Operating Margin of $207 million. Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses Transportation and Blending Operating Production and Mineral Taxes Operating Margin Capital Investment Operating Margin Net of Related Capital Investment May 17 – December 31, 2017 555 41 514 56 250 1 207 225 (18) Oil Sands – Capital Investment DD&A We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. In 2017, Oil Sands DD&A increased $575 million primarily due to higher sales volumes as a result of the Acquisition. The average depletion rate was approximately $11.50 per barrel compared with $11.30 per barrel in 2016. Our DD&A rate increased primarily due to an increase in the carrying value of our assets as a result of the re-measurement of our pre-existing interest in FCCL and the acquisition of the additional 50 percent interest of FCCL, which was partially offset by proved reserve additions. Future development costs declined due to cost savings at both Foster Creek and Christina Lake related to a reduction in per well costs and increased well pair spacing. This decline was partially offset by an increase in costs related to the expansion of the development area and inclusion of phase G costs at Christina Lake. Exploration Expense For the year ended December 31, 2017, Management has determined that costs incurred to date on certain E&E assets, primarily in the Greater Borealis area, were not recoverable. As a result, $888 million of previously capitalized costs were recorded as exploration expense. In 2016, exploration expense was $2 million. Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects. These assets reside primarily in the Borealis cash-generating unit (“CGU”) within the Oil Sands segment. DEEP BASIN On May 17, 2017, we acquired the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets including undeveloped land, exploration and production assets, and related infrastructure in Alberta and British Columbia. Our Deep Basin Assets include approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average working interest of 70 percent. In addition, the Deep Basin Assets include interests in numerous natural gas processing plants with an estimated net processing capacity of 1.4 Bcf per day. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement our long-term oil sands development. We have now successfully integrated the Deep Basin Assets, maintained business continuity and continue to deliver safe and reliable operations. 2017 2016 455 426 881 12 34 1 45 973 263 282 545 7 16 6 30 604 2015 403 647 1,050 47 24 38 26 1,185 ($ millions) Foster Creek Christina Lake Narrows Lake Telephone Lake Grand Rapids (1) Other (2) Capital Investment (3) Existing Projects Emerging Projects Drilling Activity Foster Creek Christina Lake Narrows Lake Telephone Lake Other (2) Grand Rapids asset was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017. (1) (2) (3) Includes new resource plays and Athabasca natural gas. Includes expenditures on PP&E, E&E assets and assets held for sale. Capital investment in 2017 increased by $369 million from 2016, reflecting our 100 percent ownership of FCCL as of May 17, 2017. At Foster Creek, capital investment in 2017 was focused on sustaining capital related to existing production and stratigraphic test wells. In 2016, capital investment included sustaining capital related to existing production and stratigraphic test wells, as well as capital associated with the completion of phase G. In 2017, Christina Lake capital investment focused on sustaining capital related to existing production, the phase G expansion and stratigraphic test wells. In 2016, capital was focused on sustaining capital related to existing production, the completion of expansion phase F and stratigraphic test wells. Capital investment at Narrows Lake in 2017 and 2016 primarily related to drilling of stratigraphic test wells to further progress the project, as well as preservation of equipment at site. In 2017, Telephone Lake capital investment concentrated on drilling stratigraphic test wells to further assess the project. In 2016, spending was reduced in response to the low commodity price environment and focused on front-end engineering work for the central processing facility. Gross Stratigraphic Test Wells Gross Production Wells (1) 2016 2017 2016 2015 2017 2015 96 108 204 2 13 1 220 95 104 199 1 - 5 124 40 164 - - - 205 164 41 25 66 - - - 66 18 35 53 - - 1 54 28 67 95 - - 1 96 SAGD well pairs are counted as a single producing well. (1) (2) Includes Grand Rapids which was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017. Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and near-term expansion phases and to further progress the evaluation of emerging assets. Future Capital Investment production. Foster Creek is currently producing from phases A through G. Capital investment for 2018 is forecast to be between $500 million and $550 million. We plan to continue focusing on sustaining capital related to existing Christina Lake is producing from phases A through F. Capital investment for 2018 is forecast to be between $500 million and $550 million, focused on sustaining capital and construction of the phase G expansion. Field construction of phase G, which has an initial design capacity of 50,000 barrels per day, is progressing well and remains on track. Phase G is expected to start producing in the second half of 2019. Capital investment at Narrows Lake in 2018 is forecast to be between $5 million and $10 million and will focus primarily on equipment preservation related to the suspension of construction at Narrows Lake. In 2018, our Technology and other capital, forecast to be between $35 million and $45 million, relates to technology development initiatives and annual environmental and regulatory commitments. Our 2018 Oil Sands capital investment is forecast to be between $1,040 million and $1,155 million. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Successful integration of the Deep Basin Assets; Total capital investment of $225 million related to the drilling of 28 horizontal production wells targeting liquids rich natural gas, the completion of 20 wells, and bringing 14 wells on production; Netback of $7.32 per BOE; Total production from the date of the Acquisition averaging 117,138 BOE per day, equivalent to 73,492 BOE per day for the year; and Generating Operating Margin of $207 million. Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses Transportation and Blending Operating Production and Mineral Taxes Operating Margin Capital Investment Operating Margin Net of Related Capital Investment May 17 – December 31, 2017 555 41 514 56 250 1 207 225 (18) 2017 ANNUAL REPORT | 23 Significant developments in our Deep Basin segment in 2017 include: • • • • • Revenues Price NGLs ($/bbl) Light and Medium Oil ($/bbl) Natural Gas ($/mcf) Total Oil Equivalent ($/BOE) May 17 – December 31, 2017 33.05 60.01 2.03 19.52 Our Deep Basin Assets produce a variety of products from natural gas, condensate, other NGLs (including ethane, propane, butane and pentane) and light and medium oil. In 2017, revenues included $31 million of processing fee revenue related to our interests in natural gas processing facilities. We do not include processing fee revenue in our per-unit pricing metrics or our netbacks. Production Volumes Liquids NGLs (barrels per day) Light and Medium Oil (barrels per day) Natural Gas (MMcf per day) Total Production (BOE/day) Natural Gas Production (percentage of total) Liquids Production (percentage of total) Royalties 2017 16,928 3,922 20,850 316 73,492 72% 28% The Deep Basin Assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties benefit from a number of different programs that reduce the royalty rate on natural gas production. Natural gas wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital and operating costs incurred to process and transport the Crown’s portion of natural gas production. Effective January 1, 2017, the Alberta Government released a new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”), which applies to all producing wells after January 1, 2017. Under this new framework, Cenovus will pay a five percent pre-payout royalty on all production until the total revenue from a well equals the drilling and completion cost allowance calculated for each well that meets certain MRF criteria. Subsequently, a higher post-payout royalty rate will apply and will vary based on product-specific market prices. Once a well reaches a maturity threshold, the royalty rate will drop to better match declining production rates. Wells drilled before January 1, 2017 will be managed under the old framework until 2027 and then will convert to the MRF. In British Columbia, royalties also benefit from programs to reduce the rate on natural gas production. British Columbia applies a GCA, but only on natural gas processed through producer-owned plants. British Columbia also offers a Producer Cost of Service allowance, which reduces the royalty for the processing of the Crown’s portion of natural gas production. In 2017, our effective royalty rate was 12.1 percent for liquids and 4.4 percent for natural gas. Expenses Transportation Transportation costs capture charges for the movement of crude oil, natural gas and NGLs from the point of production to where the product is sold. In 2017, the majority of Deep Basin products were sold into the Alberta market. Transportation costs averaged $2.08 per BOE in 2017. Operating Primary drivers of our operating expenses in 2017 were related to workforce, repairs and maintenance, processing fee expenses, and property tax and lease costs. Since the Acquisition, optimization of maintenance processes has enabled the extension of maintenance intervals, resulting in increased runtimes and lower repairs and maintenance costs. In 2017, Deep Basin operating costs were $8.56 per BOE, in line with our expectations. 24 | CENOVUS ENERGY In 2017, capital investment was focused on developing all three operating areas, and included the drilling of 24 net horizontal wells in addition to participating in the drilling of four non-operated net horizontal wells targeting liquids rich natural gas. The Elmworth-Wapiti operating area focused on drilling nine net horizontal production wells within the Falher and Montney plays, with five net completions. The Kaybob-Edson operating area focused on drilling seven net horizontal production wells within the Spirit River play and five net completions. The Clearwater operating area focused on drilling 12 net horizontal production wells within the Spirit River play and 10 net Netbacks ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Production and Mineral Taxes Netback Excluding Realized Risk Management Realized Risk Management Gain (Loss) Netback Including Realized Risk Management Deep Basin – Capital Investment completions. Drilling and Completions ($ millions) Facilities Other Capital Investment (1) Drilling Activity (1) Includes expenditures on PP&E, E&E assets and assets held for sale. (net wells, unless otherwise stated) Drilled(1) Completed Tied-in Future Capital Investment (1) Includes 24 net horizontal wells and four non-operated net horizontal wells. May 17 – December 31, 2017 19.52 1.54 2.08 8.56 0.02 7.32 - 7.32 May 17 – December 31, 2017 152 32 41 225 28 20 14 May 17 – December 31, 2017 Our 2018 Deep Basin capital investment is forecast to be between $175 million and $195 million. We are taking a disciplined development approach in the Deep Basin in 2018. We plan to focus capital investment on a number of drilling, completion and tie-in opportunities that have the potential to generate strong returns and increase throughput at facilities that are currently underutilized. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. DD&A We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. As at December 31, 2017, it was determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional DD&A. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan. Total Deep Basin DD&A was $331 million in 2017. Assets and Liabilities Held for Sale In December 2017, we commenced marketing for sale certain non-core assets located in the East and West Clearwater areas. The properties currently produce approximately 15,000 BOE per day of natural gas and liquids. These assets were reclassified as assets held for sale and recorded at the lesser of their carrying amount and fair value less costs to sell. May 17 – December 31, 2017 33.05 60.01 2.03 19.52 2017 16,928 3,922 20,850 316 73,492 72% 28% Revenues Price NGLs ($/bbl) Light and Medium Oil ($/bbl) Natural Gas ($/mcf) Total Oil Equivalent ($/BOE) Production Volumes Liquids NGLs (barrels per day) Light and Medium Oil (barrels per day) Natural Gas (MMcf per day) Total Production (BOE/day) Natural Gas Production (percentage of total) Liquids Production (percentage of total) Royalties Our Deep Basin Assets produce a variety of products from natural gas, condensate, other NGLs (including ethane, propane, butane and pentane) and light and medium oil. In 2017, revenues included $31 million of processing fee revenue related to our interests in natural gas processing facilities. We do not include processing fee revenue in our per-unit pricing metrics or our netbacks. The Deep Basin Assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties benefit from a number of different programs that reduce the royalty rate on natural gas production. Natural gas wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital and operating costs incurred to process and transport the Crown’s portion of natural gas production. Effective January 1, 2017, the Alberta Government released a new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”), which applies to all producing wells after January 1, 2017. Under this new framework, Cenovus will pay a five percent pre-payout royalty on all production until the total revenue from a well equals the drilling and completion cost allowance calculated for each well that meets certain MRF criteria. Subsequently, a higher post-payout royalty rate will apply and will vary based on product-specific market prices. Once a well reaches a maturity threshold, the royalty rate will drop to better match declining production rates. Wells drilled before January 1, 2017 will be managed under the old framework until 2027 and then will convert to the MRF. In British Columbia, royalties also benefit from programs to reduce the rate on natural gas production. British Columbia applies a GCA, but only on natural gas processed through producer-owned plants. British Columbia also offers a Producer Cost of Service allowance, which reduces the royalty for the processing of the Crown’s portion of natural gas production. In 2017, our effective royalty rate was 12.1 percent for liquids and 4.4 percent for natural gas. Expenses Transportation Operating Transportation costs capture charges for the movement of crude oil, natural gas and NGLs from the point of production to where the product is sold. In 2017, the majority of Deep Basin products were sold into the Alberta market. Transportation costs averaged $2.08 per BOE in 2017. Primary drivers of our operating expenses in 2017 were related to workforce, repairs and maintenance, processing fee expenses, and property tax and lease costs. Since the Acquisition, optimization of maintenance processes has enabled the extension of maintenance intervals, resulting in increased runtimes and lower repairs and maintenance costs. In 2017, Deep Basin operating costs were $8.56 per BOE, in line with our expectations. Netbacks ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Production and Mineral Taxes Netback Excluding Realized Risk Management Realized Risk Management Gain (Loss) Netback Including Realized Risk Management Deep Basin – Capital Investment May 17 – December 31, 2017 19.52 1.54 2.08 8.56 0.02 7.32 - 7.32 In 2017, capital investment was focused on developing all three operating areas, and included the drilling of 24 net horizontal wells in addition to participating in the drilling of four non-operated net horizontal wells targeting liquids rich natural gas. The Elmworth-Wapiti operating area focused on drilling nine net horizontal production wells within the Falher and Montney plays, with five net completions. The Kaybob-Edson operating area focused on drilling seven net horizontal production wells within the Spirit River play and five net completions. The Clearwater operating area focused on drilling 12 net horizontal production wells within the Spirit River play and 10 net completions. ($ millions) Drilling and Completions Facilities Other Capital Investment (1) (1) Includes expenditures on PP&E, E&E assets and assets held for sale. Drilling Activity (net wells, unless otherwise stated) Drilled(1) Completed Tied-in May 17 – December 31, 2017 152 32 41 225 May 17 – December 31, 2017 28 20 14 (1) Includes 24 net horizontal wells and four non-operated net horizontal wells. Future Capital Investment Our 2018 Deep Basin capital investment is forecast to be between $175 million and $195 million. We are taking a disciplined development approach in the Deep Basin in 2018. We plan to focus capital investment on a number of drilling, completion and tie-in opportunities that have the potential to generate strong returns and increase throughput at facilities that are currently underutilized. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. DD&A We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. As at December 31, 2017, it was determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional DD&A. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan. Total Deep Basin DD&A was $331 million in 2017. Assets and Liabilities Held for Sale In December 2017, we commenced marketing for sale certain non-core assets located in the East and West Clearwater areas. The properties currently produce approximately 15,000 BOE per day of natural gas and liquids. These assets were reclassified as assets held for sale and recorded at the lesser of their carrying amount and fair value less costs to sell. 2017 ANNUAL REPORT | 25 REFINING AND MARKETING Cenovus is a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. and operated by our partner, Phillips 66. Our Refining and Marketing segment positions us to capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to the Refineries. This segment captures our marketing and transportation initiatives as well as our crude-by-rail terminal operations located in Bruderheim, Alberta. In 2017, we loaded an average of 12,176 gross barrels per day (2016 – 11,584 gross barrels per day). Significant developments that impacted our Refining and Marketing segment in 2017 compared with 2016 include: • • Generating Operating Margin of $598 million, a 73 percent increase from 2016; and Maintaining strong crude utilization and operating performance at the Refineries. Refinery Operations (1) Crude Oil Capacity (Mbbls/d) Crude Oil Runs (Mbbls/d) Heavy Crude Oil Light/Medium Refined Products (Mbbls/d) Gasoline Distillate Other Crude Utilization (percent) (1) Represents 100 percent of the Wood River and Borger refinery operations. 2017 2016 2015 460 442 202 240 470 238 149 83 96 460 444 233 211 471 236 146 89 97 460 419 200 219 444 228 137 79 91 On a 100 percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in the Refineries relative to the total capacity. Crude oil runs and refined product output in 2017 were consistent with 2016. The planned turnarounds and maintenance and unplanned maintenance at both refineries in 2017 had a similar impact on crude oil runs and refined product output as the planned and unplanned maintenance in 2016. Lower heavy crude oil volumes were processed due to optimization of the total crude input slate. Financial Results ($ millions) Revenues Purchased Product Gross Margin Expenses Operating (Gain) Loss on Risk Management Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Gross Margin 2017 9,852 8,476 1,376 772 6 598 180 418 2016 8,439 7,325 1,114 742 26 346 220 126 2015 8,805 7,709 1,096 754 (43) 385 248 137 The refining realized crack spread, which is the gross margin on a per barrel basis, is affected by many factors, such as the variety of feedstock crude oil processed; refinery configuration and the proportion of gasoline, distillate and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the Refineries; and the cost of feedstock. Feedstock costs are valued on a FIFO accounting basis. In 2017, Refining and Marketing gross margin increased primarily due to: • • Higher average market crack spreads; and Increased margins on the sale of our secondary products, such as NGLs, due to higher realized prices. These increases in gross margin were partially offset by: • • Narrowing heavy crude oil differentials, increasing the cost of purchased crude; and The strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact of approximately $27 million on our gross margin. 26 | CENOVUS ENERGY The costs associated with Renewable Identification Numbers (“RINs”) were $296 million in 2017 (2016 – $294 million). The costs of RINs remained relatively consistent as the decrease in RINs benchmark prices was offset by an increase in the required RINs volume obligation. Operating Expense Primary drivers of operating expenses were labour, maintenance, utilities and supplies. In 2017, operating expenses increased due to an increase in maintenance costs associated with the plant turnarounds in the first quarter of 2017, and higher utility costs resulting from higher natural gas prices. Refining and Marketing – Capital Investment 2017 114 54 12 180 2016 147 66 7 220 2015 162 78 8 248 ($ millions) Wood River Refinery Borger Refinery Marketing quarter of 2016. DD&A in 2016. Capital expenditures in 2017 focused on capital maintenance and reliability work. Capital investment declined primarily due to the completion of work on the debottlenecking project at the Wood River refinery in the third In 2018, we expect to invest between $180 million and $210 million mainly related to capital maintenance and reliability work. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from three to 40 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A was $215 million in 2017 compared with $211 million CORPORATE AND ELIMINATIONS The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices, power costs, interest rates, and foreign exchange rates, as well as realized risk management gains, if any, on interest rate swaps and foreign exchange contracts. In 2017, our risk management activities resulted in $729 million of unrealized losses (2016 – $554 million of unrealized losses). As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. In 2017, we realized $146 million of risk management gains on foreign exchange contracts primarily due to hedging activity undertaken to support the Acquisition which were reported in the Corporate and Eliminations segment. The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, finance costs, interest income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the contingent payment, research costs, (gain) loss on divestiture of assets, and other (income) loss. ($ millions) General and Administrative Finance Costs Interest Income Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Transaction Costs Re-measurement of Contingent Payment Research Costs (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net 2017 308 645 (62) (812) (2,555) 56 (138) 36 1 (5) (2,526) 2016 326 390 (52) (198) - - - 36 6 34 542 2015 335 381 (28) 1,036 - - - 2 27 (2,392) (639) REFINING AND MARKETING Cenovus is a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. and operated by our partner, Phillips 66. Our Refining and Marketing segment positions us to capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to the Refineries. This segment captures our marketing and transportation initiatives as well as our crude-by-rail terminal operations located in Bruderheim, Alberta. In 2017, we loaded an average of 12,176 gross barrels per day (2016 – 11,584 gross barrels per day). • • Generating Operating Margin of $598 million, a 73 percent increase from 2016; and Maintaining strong crude utilization and operating performance at the Refineries. Refinery Operations (1) Crude Oil Capacity (Mbbls/d) Crude Oil Runs (Mbbls/d) Heavy Crude Oil Light/Medium Refined Products (Mbbls/d) Gasoline Distillate Other 460 442 202 240 470 238 149 83 96 2017 9,852 8,476 1,376 772 6 598 180 418 460 444 233 211 471 236 146 89 97 2016 8,439 7,325 1,114 742 26 346 220 126 460 419 200 219 444 228 137 79 91 2015 8,805 7,709 1,096 754 (43) 385 248 137 Crude Utilization (percent) (1) Represents 100 percent of the Wood River and Borger refinery operations. On a 100 percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in the Refineries relative to the total capacity. Crude oil runs and refined product output in 2017 were consistent with 2016. The planned turnarounds and maintenance and unplanned maintenance at both refineries in 2017 had a similar impact on crude oil runs and refined product output as the planned and unplanned maintenance in 2016. Lower heavy crude oil volumes were processed due to optimization of the total crude input slate. Financial Results ($ millions) Revenues Purchased Product Gross Margin Expenses Operating Operating Margin Capital Investment Gross Margin (Gain) Loss on Risk Management Operating Margin Net of Related Capital Investment The refining realized crack spread, which is the gross margin on a per barrel basis, is affected by many factors, such as the variety of feedstock crude oil processed; refinery configuration and the proportion of gasoline, distillate and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the Refineries; and the cost of feedstock. Feedstock costs are valued on a FIFO accounting basis. In 2017, Refining and Marketing gross margin increased primarily due to: Higher average market crack spreads; and Increased margins on the sale of our secondary products, such as NGLs, due to higher realized prices. These increases in gross margin were partially offset by: Narrowing heavy crude oil differentials, increasing the cost of purchased crude; and The strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact of approximately $27 million on our gross margin. • • • • Significant developments that impacted our Refining and Marketing segment in 2017 compared with 2016 include: Refining and Marketing – Capital Investment 2017 2016 2015 ($ millions) Wood River Refinery Borger Refinery Marketing 2017 114 54 12 180 2016 147 66 7 220 2015 162 78 8 248 The costs associated with Renewable Identification Numbers (“RINs”) were $296 million in 2017 (2016 – $294 million). The costs of RINs remained relatively consistent as the decrease in RINs benchmark prices was offset by an increase in the required RINs volume obligation. Operating Expense Primary drivers of operating expenses were labour, maintenance, utilities and supplies. In 2017, operating expenses increased due to an increase in maintenance costs associated with the plant turnarounds in the first quarter of 2017, and higher utility costs resulting from higher natural gas prices. Capital expenditures in 2017 focused on capital maintenance and reliability work. Capital investment declined primarily due to the completion of work on the debottlenecking project at the Wood River refinery in the third quarter of 2016. In 2018, we expect to invest between $180 million and $210 million mainly related to capital maintenance and reliability work. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. DD&A Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from three to 40 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A was $215 million in 2017 compared with $211 million in 2016. CORPORATE AND ELIMINATIONS The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices, power costs, interest rates, and foreign exchange rates, as well as realized risk management gains, if any, on interest rate swaps and foreign exchange contracts. In 2017, our risk management activities resulted in $729 million of unrealized losses (2016 – $554 million of unrealized losses). As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. In 2017, we realized $146 million of risk management gains on foreign exchange contracts primarily due to hedging activity undertaken to support the Acquisition which were reported in the Corporate and Eliminations segment. The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, finance costs, interest income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the contingent payment, research costs, (gain) loss on divestiture of assets, and other (income) loss. ($ millions) General and Administrative Finance Costs Interest Income Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Transaction Costs Re-measurement of Contingent Payment Research Costs (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net 2017 308 645 (62) (812) (2,555) 56 (138) 36 1 (5) (2,526) 2016 326 390 (52) (198) - - - 36 6 34 542 2015 335 381 (28) 1,036 - - - 27 (2,392) 2 (639) 2017 ANNUAL REPORT | 27 Expenses General and Administrative Primary drivers of our general and administrative expenses in 2017 were workforce costs and office rent. In 2017, general and administrative expenses decreased by $18 million compared with 2016 due to: • Lower long-term employee incentive costs related to a decline in our share price; • A non-cash expense of $9 million for certain Calgary office space in excess of Cenovus’s current and near-term requirements, compared with $61 million in 2016; and Lower information technology costs due to process improvements. • Office rent, which makes up a large percentage of our G&A at $95 million, was consistent with 2016. These decreases were partially offset by approximately $40 million of transitional services provided by ConocoPhillips. Under the Acquisition purchase and sales agreement, ConocoPhillips agreed to provide certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions are in the normal course of operations and are measured at the exchange amounts. Finance Costs Finance costs include interest expense on our long-term debt and short-term borrowings as well as the unwinding of the discount on decommissioning liabilities. In 2017, finance costs increased by $255 million primarily due to costs associated with additional debt incurred to finance the Acquisition, including US$2.9 billion of senior unsecured notes and $3.6 billion borrowed under a committed Bridge Facility. The committed Bridge Facility was fully repaid and retired in December 2017 with proceeds from the sale of our legacy Conventional assets and cash on hand. The weighted average interest rate on outstanding debt for 2017 was 4.9 percent (2016 – 5.3 percent). Foreign Exchange ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2017 (857) 45 (812) 2016 (189) (9) (198) 2015 1,097 (61) 1,036 In 2017, unrealized foreign exchange gains of $665 million resulted from the translation of our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar as at December 31, 2017 strengthened by seven percent in comparison to December 31, 2016. Unrealized foreign exchange gains also resulted from the translation of U.S. cash that was accumulated in advance of the Acquisition. Realized foreign exchange losses in 2017 primarily resulted from an increase in the number of sales contracts denominated in U.S. dollars. Revaluation Gain Prior to the Acquisition, our 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”) and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, we control FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and accordingly, FCCL has been consolidated. As required by IFRS 3 when control is achieved in stages, the previously held interest in FCCL was re-measured to its fair value of $12.3 billion and a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) was recorded in net earnings in the second quarter of 2017. Transaction Costs In 2017, we expensed $56 million of transaction costs related to the Acquisition. Re-measurement of Contingent Payment Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. The contingent payment is accounted for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is subsequently re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. At December 31, 2017, the contingent payment was valued at $206 million, resulting in a re-measurement gain of $138 million. In the fourth quarter of 2017, WCS averaged above $52 per barrel; therefore, $17 million is payable under this agreement. 28 | CENOVUS ENERGY DD&A $105 million). Income Tax ($ millions) Current Tax Canada United States taxes: ($ millions) Average WCS forward pricing for the remaining term of the contingent payment is US$35.51 or C$44.55 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately C$39.60 per barrel and C$52.60 per barrel. Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. DD&A in 2017 was $62 million (2016 – $65 million; 2015 – Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Total Tax Expense (Recovery) From Continuing Operations The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income 2017 2016 2015 (217) (38) (255) 203 (52) 2017 2,216 27.0% 598 (17) (148) (118) (41) (68) - (275) (5) 22 (52) (260) 1 (259) (84) (343) 2016 (802) 27.0% (217) (46) (26) (26) (46) - - - 5 13 (343) 441 (12) 429 (453) (24) 2015 890 26.1% 232 (41) 137 135 (55) (149) (415) 114 7 11 (24) Earnings (Loss) From Continuing Operations Before Income Tax Canadian Statutory Rate Expected Income Tax Expense (Recovery) From Continuing Operations Effect of Taxes Resulting From: Foreign Tax Rate Differential Non-Taxable Capital (Gains) Losses Non-Recognition of Capital (Gains) Losses Adjustments Arising From Prior Year Tax Filings (Recognition) of Previously Unrecognized Capital Losses (Recognition) of U.S. Tax Basis Change in Statutory Rate Non-Deductible Expenses Other Total Tax Expense (Recovery) From Continuing Operations Effective Tax Rate (2.3)% (42.8)% (2.7)% Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and as a result, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation. In 2017, a current tax recovery was recorded in continuing operations resulting from the carry back of current and prior year losses and an adjustment related to prior years. A deferred tax expense was recorded in 2017 compared with a recovery in 2016 on continuing operations due to the revaluation gain of our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal corporate income tax rate from 35 to 21 percent, reducing our deferred income tax liability, and the impact of E&E writedowns. • • • • • party. discontinuance. In 2017, the U.S. issued new tax legislation which: Reduces the federal income tax rate from 35 percent to 21 percent; Permits the full deductibility of allowed capital expenditures until January 1, 2023; Limits the use of operating tax losses incurred after 2017 to 80 percent of taxable income; Limits the deductibility of interest expense to 30 percent of “adjusted taxable income”; and Introduces a base erosion and anti-abuse tax that imposes a five percent minimum tax in 2018, increasing to 10 percent in 2019, to the extent that a corporation makes significant tax deductible payments to a related In 2017, we recorded an income tax expense of $404 million related to discontinued operations (2016 – income tax recovery of $39 million), of which $347 million deferred tax expense relates to the gain on Expenses General and Administrative Primary drivers of our general and administrative expenses in 2017 were workforce costs and office rent. In 2017, general and administrative expenses decreased by $18 million compared with 2016 due to: Lower long-term employee incentive costs related to a decline in our share price; A non-cash expense of $9 million for certain Calgary office space in excess of Cenovus’s current and near-term requirements, compared with $61 million in 2016; and Lower information technology costs due to process improvements. • • • Office rent, which makes up a large percentage of our G&A at $95 million, was consistent with 2016. These decreases were partially offset by approximately $40 million of transitional services provided by ConocoPhillips. Under the Acquisition purchase and sales agreement, ConocoPhillips agreed to provide certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions are in the normal course of operations and are measured at the exchange amounts. Finance costs include interest expense on our long-term debt and short-term borrowings as well as the unwinding of the discount on decommissioning liabilities. In 2017, finance costs increased by $255 million primarily due to costs associated with additional debt incurred to finance the Acquisition, including US$2.9 billion of senior unsecured notes and $3.6 billion borrowed under a committed Bridge Facility. The committed Bridge Facility was fully repaid and retired in December 2017 with proceeds from the sale of our legacy Conventional assets and cash Finance Costs on hand. Foreign Exchange ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2017 (857) 45 (812) 2016 (189) (9) (198) 2015 1,097 (61) 1,036 In 2017, unrealized foreign exchange gains of $665 million resulted from the translation of our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar as at December 31, 2017 strengthened by seven percent in comparison to December 31, 2016. Unrealized foreign exchange gains also resulted from the translation of U.S. cash that was accumulated in advance of the Acquisition. Realized foreign exchange losses in 2017 primarily resulted from an increase in the number of sales contracts denominated in U.S. dollars. Revaluation Gain Prior to the Acquisition, our 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”) and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, we control FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and accordingly, FCCL has been consolidated. As required by IFRS 3 when control is achieved in stages, the previously held interest in FCCL was re-measured to its fair value of $12.3 billion and a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) was recorded in net earnings in the second quarter of 2017. Transaction Costs In 2017, we expensed $56 million of transaction costs related to the Acquisition. Re-measurement of Contingent Payment Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. The contingent payment is accounted for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is subsequently re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. At December 31, 2017, the contingent payment was valued at $206 million, resulting in a re-measurement gain of $138 million. In the fourth quarter of 2017, WCS averaged above $52 per barrel; therefore, $17 million is payable under this agreement. Average WCS forward pricing for the remaining term of the contingent payment is US$35.51 or C$44.55 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately C$39.60 per barrel and C$52.60 per barrel. DD&A Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. DD&A in 2017 was $62 million (2016 – $65 million; 2015 – $105 million). Income Tax ($ millions) Current Tax Canada United States Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Total Tax Expense (Recovery) From Continuing Operations 2017 2016 2015 (217) (38) (255) 203 (52) (260) 1 (259) (84) (343) 441 (12) 429 (453) (24) The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: The weighted average interest rate on outstanding debt for 2017 was 4.9 percent (2016 – 5.3 percent). ($ millions) Earnings (Loss) From Continuing Operations Before Income Tax Canadian Statutory Rate Expected Income Tax Expense (Recovery) From Continuing Operations Effect of Taxes Resulting From: Foreign Tax Rate Differential Non-Taxable Capital (Gains) Losses Non-Recognition of Capital (Gains) Losses Adjustments Arising From Prior Year Tax Filings (Recognition) of Previously Unrecognized Capital Losses (Recognition) of U.S. Tax Basis Change in Statutory Rate Non-Deductible Expenses Other Total Tax Expense (Recovery) From Continuing Operations 2017 2,216 27.0% 598 (17) (148) (118) (41) (68) - (275) (5) 22 (52) 2016 (802) 27.0% (217) (46) (26) (26) (46) - - - 5 13 (343) 2015 890 26.1% 232 (41) 137 135 (55) (149) (415) 114 7 11 (24) Effective Tax Rate (2.3)% (42.8)% (2.7)% Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and as a result, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation. In 2017, a current tax recovery was recorded in continuing operations resulting from the carry back of current and prior year losses and an adjustment related to prior years. A deferred tax expense was recorded in 2017 compared with a recovery in 2016 on continuing operations due to the revaluation gain of our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal corporate income tax rate from 35 to 21 percent, reducing our deferred income tax liability, and the impact of E&E writedowns. In 2017, the U.S. issued new tax legislation which: • • • • • Reduces the federal income tax rate from 35 percent to 21 percent; Permits the full deductibility of allowed capital expenditures until January 1, 2023; Limits the use of operating tax losses incurred after 2017 to 80 percent of taxable income; Limits the deductibility of interest expense to 30 percent of “adjusted taxable income”; and Introduces a base erosion and anti-abuse tax that imposes a five percent minimum tax in 2018, increasing to 10 percent in 2019, to the extent that a corporation makes significant tax deductible payments to a related party. In 2017, we recorded an income tax expense of $404 million related to discontinued operations (2016 – income tax recovery of $39 million), of which $347 million deferred tax expense relates to the gain on discontinuance. 2017 ANNUAL REPORT | 29 Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and the actual amounts subsequently reported on the tax returns, and other permanent differences. Our effective tax rate differs from the statutory tax rate due to non-taxable foreign exchange gains and the recognition of the benefit of other capital losses and a recovery relating to the change in the U.S. federal tax rate. DISCONTINUED OPERATIONS Following the Acquisition, we announced our intention to divest all of our legacy Conventional assets and therefore the Conventional segment has been reported as a discontinued operation. Operating Margin Variance 208 544 158 8 ) s n o i l l i m $ ( 900 800 700 600 500 400 300 200 100 0 In late 2017, we sold the majority of our legacy Conventional assets. The sale of Suffield, the one remaining legacy asset as at December 31, 2017, closed on January 5, 2018 for gross proceeds of $512 million. The divestitures completed in 2017 generated total gross cash proceeds of $3.2 billion before closing adjustments and a before-tax gain of $1.3 billion. Details of the asset sales are: • On September 29, 2017, we completed the sale of our Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern Alberta, for gross cash proceeds of $975 million before closing adjustments. A before-tax loss on discontinuance of $623 million was recorded on the sale; On December 7, 2017, our Palliser crude oil and natural gas operations in southern Alberta were sold for gross cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion was recorded on the sale; and On December 14, 2017, the sale of our Weyburn assets in southern Saskatchewan was completed for gross cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was recorded on the sale. • • Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Depreciation, Depletion and Amortization Exploration Expense Finance Costs Earnings (Loss) From Discontinued Operations Before Income Tax Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) After-tax Earnings (Loss) From Discontinued Operations After-tax Gain on Discontinuance (1) Net Earnings (Loss) From Discontinued Operations (1) Net of deferred tax expense of $347 million in the year ended December 31, 2017. 2017 1,309 174 1,135 167 426 18 33 491 192 2 80 217 24 33 160 938 1,098 2016 1,267 139 1,128 186 444 12 (58) 544 567 - 102 (125) 86 (125) (86) - (86) 2015 1,648 113 1,535 229 558 17 (209) 940 1,121 71 101 (353) 145 (202) (296) - (296) 30 | CENOVUS ENERGY 91 35 19 18 491 6 Year Ended Price (1) Volume December 31, 2016 Condensate Revenue (1) Realized Risk Management Royalties Transportation and Operating Expenses Blending (1) Production and Mineral Taxes Year Ended December 31, 2017 (1) Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. 2017 52.38 2.47 32.10 2016 40.67 2.33 26.54 2015 44.31 2.92 30.51 Revenues Price Total Liquids ($/bbl) Natural Gas ($/mcf) Total Oil Equivalent ($/BOE) benchmark. Production Volumes (barrels per day) Liquids Heavy Oil Light and Medium Oil NGLs Our Conventional assets produced a variety of natural gas, NGLs, condensate and crude oils, ranging from heavy oil, which realizes a price based on the WCS benchmark, to light oil, which realizes a price closer to the WTI Total Liquids Production (barrels per day) Natural Gas (MMcf per day) 333 (12)% 377 2017 21,478 24,824 1,073 47,375 Percent Change (26)% (4)% 1% (16)% 2016 29,185 25,915 1,065 56,165 Percent Change (15)% (10)% (7)% (12)% (8)% 2015 34,256 28,675 1,149 64,080 412 Total Production (BOE per day) 102,855 (14)% 118,998 (10)% 132,746 Total production decreased primarily due to the divestiture of our Conventional assets late in 2017 and expected natural declines. These decreases were partially offset by an increase in production associated with our tight oil drilling program in southern Alberta. Condensate Heavy oil currently must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Blending ratios for Conventional heavy oil ranged between 10 percent and 16 percent. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the WCS-Condensate differential in 2017, the proportion of the cost of condensate recovered Royalties increased $35 million in 2017 primarily due to an increase in our liquids sales prices, higher royalty rates, and lower allowable costs for royalty purposes at Weyburn and Pelican Lake, partially offset by a reduction in sales volumes. In 2017, the effective liquids royalty rate was 19.3 percent (2016 – 16.3 percent) and the average natural gas royalty rate was 4.8 percent (2016 – 4.7 percent). increased. Royalties Expenses Transportation and Blending Transportation and blending costs decreased $19 million in 2017 primarily due to the sale of Pelican Lake completed on September 29, 2017, resulting in lower production as well as a decrease in blended condensate volumes. This decrease was partially offset by higher blending costs as a result of increased condensate prices. Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and the actual amounts subsequently reported on the tax returns, and other permanent differences. Our effective tax rate differs from the statutory tax rate due to non-taxable foreign exchange gains and the recognition of the benefit of other capital losses and a recovery relating to the change in the U.S. federal tax rate. DISCONTINUED OPERATIONS Following the Acquisition, we announced our intention to divest all of our legacy Conventional assets and therefore the Conventional segment has been reported as a discontinued operation. In late 2017, we sold the majority of our legacy Conventional assets. The sale of Suffield, the one remaining legacy asset as at December 31, 2017, closed on January 5, 2018 for gross proceeds of $512 million. The divestitures completed in 2017 generated total gross cash proceeds of $3.2 billion before closing adjustments and a before-tax gain of $1.3 billion. Details of the asset sales are: On September 29, 2017, we completed the sale of our Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern Alberta, for gross cash proceeds of $975 million before closing adjustments. A before-tax loss on discontinuance of $623 million was recorded on the sale; On December 7, 2017, our Palliser crude oil and natural gas operations in southern Alberta were sold for gross cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion was recorded on the sale; and was recorded on the sale. On December 14, 2017, the sale of our Weyburn assets in southern Saskatchewan was completed for gross cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million • • • Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Depreciation, Depletion and Amortization Exploration Expense Finance Costs Earnings (Loss) From Discontinued Operations Before Income Tax Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) After-tax Earnings (Loss) From Discontinued Operations After-tax Gain on Discontinuance (1) Net Earnings (Loss) From Discontinued Operations 1,098 (1) Net of deferred tax expense of $347 million in the year ended December 31, 2017. 2017 1,309 174 1,135 167 426 18 33 491 192 2 80 217 24 33 160 938 2016 1,267 139 1,128 186 444 12 (58) 544 567 - 102 (125) 86 (125) (86) - (86) 2015 1,648 113 1,535 229 558 17 (209) 940 1,121 71 101 (353) 145 (202) (296) - (296) Operating Margin Variance 208 544 158 8 91 35 19 18 491 6 ) s n o i l l i m $ ( 900 800 700 600 500 400 300 200 100 0 Year Ended December 31, 2016 Price (1) Volume Condensate Revenue (1) Realized Risk Management Royalties Transportation and Blending (1) Operating Expenses Production and Mineral Taxes Year Ended December 31, 2017 (1) Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. Revenues Price Total Liquids ($/bbl) Natural Gas ($/mcf) Total Oil Equivalent ($/BOE) 2017 52.38 2.47 32.10 2016 40.67 2.33 26.54 2015 44.31 2.92 30.51 Our Conventional assets produced a variety of natural gas, NGLs, condensate and crude oils, ranging from heavy oil, which realizes a price based on the WCS benchmark, to light oil, which realizes a price closer to the WTI benchmark. Production Volumes (barrels per day) Liquids Heavy Oil Light and Medium Oil NGLs Total Liquids Production (barrels per day) 2017 21,478 24,824 1,073 47,375 Percent Change (26)% (4)% 1% (16)% 2016 29,185 25,915 1,065 56,165 Natural Gas (MMcf per day) 333 (12)% 377 Percent Change (15)% (10)% (7)% (12)% (8)% 2015 34,256 28,675 1,149 64,080 412 Total Production (BOE per day) 102,855 (14)% 118,998 (10)% 132,746 Total production decreased primarily due to the divestiture of our Conventional assets late in 2017 and expected natural declines. These decreases were partially offset by an increase in production associated with our tight oil drilling program in southern Alberta. Condensate Heavy oil currently must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Blending ratios for Conventional heavy oil ranged between 10 percent and 16 percent. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the WCS-Condensate differential in 2017, the proportion of the cost of condensate recovered increased. Royalties Royalties increased $35 million in 2017 primarily due to an increase in our liquids sales prices, higher royalty rates, and lower allowable costs for royalty purposes at Weyburn and Pelican Lake, partially offset by a reduction in sales volumes. In 2017, the effective liquids royalty rate was 19.3 percent (2016 – 16.3 percent) and the average natural gas royalty rate was 4.8 percent (2016 – 4.7 percent). Expenses Transportation and Blending Transportation and blending costs decreased $19 million in 2017 primarily due to the sale of Pelican Lake completed on September 29, 2017, resulting in lower production as well as a decrease in blended condensate volumes. This decrease was partially offset by higher blending costs as a result of increased condensate prices. 2017 ANNUAL REPORT | 31 Operating QUARTERLY RESULTS Primary drivers of our operating expenses in 2017 were property taxes and lease costs, workforce costs, workover activities, electricity, and repairs and maintenance. Operating expenses increased $1.02 per barrel. The per unit increase was primarily due to lower production volumes, an increase in repairs and maintenance activities, and higher energy costs. This increase was partially offset by reduced workforce costs, lower property and lease costs, fewer workovers and a decrease in electricity costs due to lower consumption and price. In 2017, production and mineral taxes increased due to the rise in crude oil prices. Netbacks ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Production and Mineral Taxes Netback Excluding Realized Risk Management Realized Risk Management Gain (Loss) Netback Including Realized Risk Management Risk Management 2017 32.10 4.65 1.93 11.25 0.49 13.78 (0.88) 12.90 2016 26.54 3.18 2.08 10.23 0.27 10.78 1.45 12.23 2015 30.51 2.33 1.88 11.58 0.35 14.37 4.50 18.87 ) l b b / $ S U e g a r e v a ( 75 65 55 45 35 25 15 Our quarterly results over the last eight quarters were impacted primarily by volatility in commodity prices, with the Acquisition having a significant impact on the last three quarters. Crude oil prices reached a 13 year low, with WTI averaging US$33.45 per barrel in the first quarter of 2016 and gradually increasing to an average of US$55.40 per barrel in the fourth quarter of 2017. Average WTI and WCS benchmark prices increased 12 percent and 23 percent, respectively in the fourth quarter 2017 compared with 2016. Our companywide Netback from continuing operations of $22.38 per BOE in the fourth quarter of 2017, before realized risk management activities, increased six percent compared with 2016. Crude Oil Benchmarks Risk management activities for 2017 resulted in realized losses of $33 million (2016 – realized gains of $58 million), consistent with average benchmark prices exceeding our contract prices. Net Earnings (Loss) From Discontinued Operations Net Earnings From Discontinued Operations was $1,098 million in 2017 compared with a loss of $86 million in 2016. The significant increase was due to the after-tax gain on discontinuance of $938 million, and lower DD&A expense due to the decision to divest our Conventional assets, partially offset by higher tax expense and a decline in operating margin. Conventional – Capital Investment ($ millions) Heavy Oil Light and Medium Oil Natural Gas Capital Investment (1) (1) Includes expenditures on PP&E, E&E assets, and assets held for sale. 2017 32 163 11 206 2016 44 117 10 171 2015 63 168 13 244 Capital investment in 2017 was primarily related to sustaining capital, the purchase of CO2 at Weyburn, and tight oil drilling opportunities in southern Alberta. Our drilling program was suspended early in the third quarter of 2017 in anticipation of the asset divestitures. Capital investment increased compared with 2016 as a result of limited crude oil capital investment activities in 2016 in response to the low commodity price environment. DD&A We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. DD&A decreased $375 million year over year primarily due to impairment losses of $445 million recorded in 2016, and a decline in sales volumes. In addition, on classification of our Conventional assets as held for sale in the first and second quarters of 2017, DD&A was no longer recorded, as required by IFRS. 32 | CENOVUS ENERGY Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 2018 Q2 2018 Q3 2018 Q4 2018 2016 2017 Forward Pricing at December 31, 2017 Brent C5 @ Edmonton WTI WCS 2017 2016 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Total Liquids (barrels per day) 422,157 449,055 333,664 234,914 219,551 208,072 198,080 197,551 Natural Gas (MMcf/d) 795 851 620 363 379 392 399 408 Total Production (BOE per day) 554,606 590,851 436,929 295,414 282,718 273,405 264,580 265,551 Operations (BOE per day) 480,497 478,817 322,792 184,001 167,230 156,591 145,604 140,808 ($ millions, except per share amounts or where otherwise indicated) Production Volumes Total Production From Continuing Refinery Operations Crude Oil Runs (Mbbls/d) Refined Products (Mbbls/d) Revenues Operating Margin (1) From Continuing Operations Total Operating Margin Cash From Operating Activities From Continuing Operations Total Cash From Operating Activities Adjusted Funds Flow (2) From Continuing Operations Total Adjusted Funds Flow Operating Earnings (Loss) (2) From Continuing Operations Per Share – Diluted ($) Total Operating Earnings (Loss) Per Share – Diluted ($) Net Earnings (Loss) From Continuing Operations Per Share – Basic and Diluted ($) Total Net Earnings (Loss) Per Share – Basic and Diluted ($) Capital Investment (3) From Continuing Operations Total Capital Investment Dividends Cash Dividends Per Share ($) (1) (2) (3) (4) reflect this classification. 5,079 4,386 4,037 3,541 3,324 2,945 2,746 1,991 450 480 462 490 1,018 1,088 1,097 1,214 449 476 572 731 481 1,102 592 1,239 833 900 796 866 (533) (0.43) (514) (0.42) (776) (0.63) 620 0.50 557 583 61 0.05 865 980 240 0.20 327 0.27 275 0.22 (82) (0.07) 396 438 62 0.05 603 745 298 0.27 352 0.32 2,558 2.30 2,617 2.35 277 327 61 0.05 406 433 305 450 195 328 183 323 (39) (0.05) (39) (0.05) 211 0.25 211 0.25 225 313 41 0.05 421 448 442 595 22 164 382 535 21 0.03 321 0.39 (209) (0.25) 91 0.11 202 259 42 0.05 463 494 335 487 189 310 296 422 (40) (0.05) (236) (0.28) (55) (0.07) (251) (0.30) 167 208 41 0.05 458 483 424 541 121 205 352 440 (3) - (39) (0.05) (231) (0.28) (267) (0.32) 202 236 42 0.05 435 460 22 144 94 182 (65) 26 (269) (0.32) (423) (0.51) 36 0.04 (118) (0.14) 284 323 41 0.05 Additional subtotal found in Note 1 and Note 11 of the Consolidated Financial Statements and defined in this MD&A. Non-GAAP measure defined in this MD&A. Includes expenditures on PP&E, E&E assets, and assets held for sale. In the second quarter of 2017, the Company’s Conventional segment was classified as a discontinued operation. Prior periods have been restated to Primary drivers of our operating expenses in 2017 were property taxes and lease costs, workforce costs, workover activities, electricity, and repairs and maintenance. Operating expenses increased $1.02 per barrel. The per unit increase was primarily due to lower production volumes, an increase in repairs and maintenance activities, and higher energy costs. This increase was partially offset by reduced workforce costs, lower property and lease costs, fewer workovers and a decrease in electricity costs due to lower consumption and price. In 2017, production and mineral taxes increased due to the rise in crude oil prices. Operating Netbacks ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Production and Mineral Taxes Netback Excluding Realized Risk Management Realized Risk Management Gain (Loss) Netback Including Realized Risk Management Risk Management 2017 32.10 4.65 1.93 11.25 0.49 13.78 (0.88) 12.90 2016 26.54 3.18 2.08 10.23 0.27 10.78 1.45 12.23 2015 30.51 2.33 1.88 11.58 0.35 14.37 4.50 18.87 QUARTERLY RESULTS Our quarterly results over the last eight quarters were impacted primarily by volatility in commodity prices, with the Acquisition having a significant impact on the last three quarters. Crude oil prices reached a 13 year low, with WTI averaging US$33.45 per barrel in the first quarter of 2016 and gradually increasing to an average of US$55.40 per barrel in the fourth quarter of 2017. Average WTI and WCS benchmark prices increased 12 percent and 23 percent, respectively in the fourth quarter 2017 compared with 2016. Our companywide Netback from continuing operations of $22.38 per BOE in the fourth quarter of 2017, before realized risk management activities, increased six percent compared with 2016. Crude Oil Benchmarks ) l b b / $ S U e g a r e v a ( 75 65 55 45 35 25 15 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 2018 Q2 2018 Q3 2018 Q4 2018 2016 2017 Forward Pricing at December 31, 2017 Brent C5 @ Edmonton WTI WCS Risk management activities for 2017 resulted in realized losses of $33 million (2016 – realized gains of $58 million), consistent with average benchmark prices exceeding our contract prices. Net Earnings (Loss) From Discontinued Operations Net Earnings From Discontinued Operations was $1,098 million in 2017 compared with a loss of $86 million in 2016. The significant increase was due to the after-tax gain on discontinuance of $938 million, and lower DD&A expense due to the decision to divest our Conventional assets, partially offset by higher tax expense and a decline ($ millions, except per share amounts or where otherwise indicated) Production Volumes Total Liquids (barrels per day) Natural Gas (MMcf/d) Total Production (BOE per day) Total Production From Continuing 2017 2016 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 422,157 449,055 333,664 234,914 363 554,606 590,851 436,929 295,414 795 620 851 219,551 379 282,718 208,072 392 273,405 198,080 399 264,580 197,551 408 265,551 Conventional – Capital Investment in operating margin. ($ millions) Heavy Oil Light and Medium Oil Natural Gas Capital Investment (1) (1) Includes expenditures on PP&E, E&E assets, and assets held for sale. 2017 32 163 11 206 2016 44 117 10 171 2015 63 168 13 244 Capital investment in 2017 was primarily related to sustaining capital, the purchase of CO2 at Weyburn, and tight oil drilling opportunities in southern Alberta. Our drilling program was suspended early in the third quarter of 2017 in anticipation of the asset divestitures. Capital investment increased compared with 2016 as a result of limited crude oil capital investment activities in 2016 in response to the low commodity price environment. DD&A We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. DD&A decreased $375 million year over year primarily due to impairment losses of $445 million recorded in 2016, and a decline in sales volumes. In addition, on classification of our Conventional assets as held for sale in the first and second quarters of 2017, DD&A was no longer recorded, as required by IFRS. Operations (BOE per day) 480,497 478,817 322,792 184,001 167,230 156,591 145,604 140,808 Refinery Operations Crude Oil Runs (Mbbls/d) Refined Products (Mbbls/d) Revenues Operating Margin (1) From Continuing Operations Total Operating Margin Cash From Operating Activities From Continuing Operations Total Cash From Operating Activities Adjusted Funds Flow (2) From Continuing Operations Total Adjusted Funds Flow Operating Earnings (Loss) (2) From Continuing Operations Per Share – Diluted ($) Total Operating Earnings (Loss) Per Share – Diluted ($) Net Earnings (Loss) From Continuing Operations Per Share – Basic and Diluted ($) Total Net Earnings (Loss) Per Share – Basic and Diluted ($) Capital Investment (3) From Continuing Operations Total Capital Investment Dividends Cash Dividends Per Share ($) 450 480 5,079 1,018 1,088 833 900 796 866 (533) (0.43) (514) (0.42) (776) (0.63) 620 0.50 557 583 61 0.05 462 490 4,386 1,097 1,214 449 476 4,037 572 731 481 1,102 592 1,239 865 980 240 0.20 327 0.27 275 0.22 (82) (0.07) 396 438 62 0.05 603 745 298 0.27 352 0.32 2,558 2.30 2,617 2.35 277 327 61 0.05 406 433 3,541 421 448 3,324 463 494 2,945 458 483 2,746 435 460 1,991 305 450 195 328 183 323 (39) (0.05) (39) (0.05) 211 0.25 211 0.25 225 313 41 0.05 442 595 22 164 382 535 21 0.03 321 0.39 (209) (0.25) 91 0.11 202 259 42 0.05 335 487 189 310 296 422 (40) (0.05) (236) (0.28) (55) (0.07) (251) (0.30) 167 208 41 0.05 424 541 121 205 352 440 (3) - (39) (0.05) (231) (0.28) (267) (0.32) 202 236 42 0.05 22 144 94 182 (65) 26 (269) (0.32) (423) (0.51) 36 0.04 (118) (0.14) 284 323 41 0.05 (1) (2) (3) (4) Additional subtotal found in Note 1 and Note 11 of the Consolidated Financial Statements and defined in this MD&A. Non-GAAP measure defined in this MD&A. Includes expenditures on PP&E, E&E assets, and assets held for sale. In the second quarter of 2017, the Company’s Conventional segment was classified as a discontinued operation. Prior periods have been restated to reflect this classification. 2017 ANNUAL REPORT | 33 Fourth Quarter 2017 Results Compared With the Fourth Quarter 2016 Continuing Operations Production Volumes Total production from continuing operations increased 187 percent in the fourth quarter of 2017 compared with 2016. The increase in production was primarily due to the Acquisition and the incremental production volumes from Christina Lake phase F, which started up in the fourth quarter of 2016. Refinery Operations Crude oil runs and refined product output increased in 2017 primarily due to unplanned outages at the Borger refinery in the fourth quarter of 2016. Revenues Revenues increased $1,755 million in 2017 primarily due to: • A rise in sales volumes due to the Acquisition and the incremental production volumes from Christina Lake phase F; A 25 percent rise in our liquids sales prices from continuing operations to $45.85 per barrel; and An increase in refining revenues largely due to higher refined product pricing. The increases to revenues were partially offset by lower revenues from third-party crude oil and natural gas sales undertaken by the marketing group, the strengthening of the Canadian dollar relative to the U.S. dollar, as well as higher crude oil royalties. Operating Margin Operating Margin from continuing operations increased 130 percent in the fourth quarter of 2017 compared with 2016. Upstream Operating Margin rose 111 percent primarily due to an increase in our liquids and natural gas sales volumes as a result of the Acquisition and a rise in our average liquids sales prices due to improved benchmark prices. These increases were partially offset by: • A rise in transportation and blending expenses related to higher condensate prices and a rise in condensate volumes required for our increased production; Realized risk management losses of $235 million compared with gains of $14 million in 2016; An increase in upstream operating expenses primarily due to the Acquisition; Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), increased sales volumes due to the Acquisition, and a rise in our liquids sales price; and Lower average natural gas sales prices, consistent with the decline in the AECO benchmark price. • • • • • • Discontinued Operations Production Volumes Operating Margin Total production decreased 36 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of the divestiture of our Conventional assets late in 2017 as well as expected natural declines. Operating Margin decreased 54 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of reduced sales volumes due to the sale of the majority of our legacy Conventional assets and natural declines, partially offset by a decrease in royalties. Consolidated Operations Cash From Operating Activities and Adjusted Funds Flow Total Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2017 compared with 2016, primarily due to a higher Operating Margin, as discussed above, partially offset by current income tax expense in 2017 compared with a recovery in 2016 and a rise in finance costs primarily associated with additional debt incurred to finance the Acquisition. The change in non-cash working capital in the fourth quarter of 2017 was primarily due to an increase in accounts payable and income tax payable, partially offset by an increase in accounts receivable and inventory. For 2016, the change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory, partially offset by an increase in accounts payable. Operating Earnings (Loss) Operating Earnings from continuing operations decreased $554 million in the three months ended December 31, 2017 compared with 2016. Higher Cash From Operating Activities and Adjusted Funds Flow, as discussed above, was more than offset by exploration expense of $887 million, and an increase in DD&A as a result of the Acquisition. Operating Earnings from discontinued operations of $19 million decreased $281 million in the three months ended December 31, 2017 compared with 2016 due to a decrease in production volumes and operating margin, as discussed above. In addition, 2016 included an impairment reversal of $462 million which arose primarily due to the increase in our Northern Alberta CGU’s estimated recoverable amount caused by a reduction in expected average future operating costs and lower future development costs, partially offset by a decline in estimated reserves. Net Earnings (Loss) Refining and Marketing Operating Margin increased by $206 million. The increase was primarily due to higher average market crack spreads, a rise in margins on the sale of our secondary products, and an increase in crude utilization rates. These increases were partially offset by narrowing heavy crude oil differentials, increased operating costs and the strengthening of the Canadian dollar relative to the U.S. dollar. Net loss from continuing operations for the three months ended December 31, 2017 increased $567 million compared with 2016. The increase in net loss was primarily due to lower operating earnings, as discussed above, and unrealized risk management losses of $654 million compared with $114 million in 2016, partially offset by non-operating unrealized foreign exchange losses of $51 million compared with $152 million in 2016. In addition, a deferred tax recovery of $275 million was recorded to reflect the benefit of the decreased U.S. federal corporate income tax rate. Operating Margin From Continuing Operations Variance Net earnings from discontinued operations in the fourth quarter includes a $1,378 million after-tax gain on the 249 131 206 223 129 1,018 divestiture of our Conventional segment assets. Capital Investment Capital investment from continuing operations in the fourth quarter of 2017 was $557 million, an increase of $355 million from 2016. The increase was primarily due to the drilling and completion of horizontal production wells within the Deep Basin corridor. Capital investment from discontinued operations was down 54 percent to $26 million in the fourth quarter of 2017 compared with 2016 due to reduced spending as a result of the decision to divest our legacy Conventional assets in first and second quarters of 2017. 834 268 442 ) s n o i l l i m $ ( 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Three Months Ended December 31, 2016 Upstream Price Upstream Volumes Upstream Realized Risk Management Royalties Upstream Operating Expenses Refining and Marketing Operating Margin Other (1) Three Months Ended December 31, 2017 (1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. 34 | CENOVUS ENERGY Fourth Quarter 2017 Results Compared With the Fourth Quarter 2016 Continuing Operations Production Volumes Total production from continuing operations increased 187 percent in the fourth quarter of 2017 compared with 2016. The increase in production was primarily due to the Acquisition and the incremental production volumes from Christina Lake phase F, which started up in the fourth quarter of 2016. Refinery Operations refinery in the fourth quarter of 2016. Crude oil runs and refined product output increased in 2017 primarily due to unplanned outages at the Borger Revenues phase F; Revenues increased $1,755 million in 2017 primarily due to: A rise in sales volumes due to the Acquisition and the incremental production volumes from Christina Lake A 25 percent rise in our liquids sales prices from continuing operations to $45.85 per barrel; and An increase in refining revenues largely due to higher refined product pricing. The increases to revenues were partially offset by lower revenues from third-party crude oil and natural gas sales undertaken by the marketing group, the strengthening of the Canadian dollar relative to the U.S. dollar, as well as higher crude oil royalties. Operating Margin prices. These increases were partially offset by: Operating Margin from continuing operations increased 130 percent in the fourth quarter of 2017 compared with 2016. Upstream Operating Margin rose 111 percent primarily due to an increase in our liquids and natural gas sales volumes as a result of the Acquisition and a rise in our average liquids sales prices due to improved benchmark A rise in transportation and blending expenses related to higher condensate prices and a rise in condensate volumes required for our increased production; Realized risk management losses of $235 million compared with gains of $14 million in 2016; An increase in upstream operating expenses primarily due to the Acquisition; Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), increased sales volumes due to the Acquisition, and a rise in our liquids sales price; and Lower average natural gas sales prices, consistent with the decline in the AECO benchmark price. Refining and Marketing Operating Margin increased by $206 million. The increase was primarily due to higher average market crack spreads, a rise in margins on the sale of our secondary products, and an increase in crude utilization rates. These increases were partially offset by narrowing heavy crude oil differentials, increased operating costs and the strengthening of the Canadian dollar relative to the U.S. dollar. Operating Margin From Continuing Operations Variance 834 268 442 249 131 206 223 129 1,018 • • • • • • • • ) s n o i l l i m $ ( 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Three Months Ended December 31, 2016 Upstream Price Upstream Volumes Upstream Realized Risk Royalties Upstream Operating Refining and Marketing Other (1) Management Expenses Operating Margin Three Months Ended December 31, 2017 (1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. Discontinued Operations Production Volumes Total production decreased 36 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of the divestiture of our Conventional assets late in 2017 as well as expected natural declines. Operating Margin Operating Margin decreased 54 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of reduced sales volumes due to the sale of the majority of our legacy Conventional assets and natural declines, partially offset by a decrease in royalties. Consolidated Operations Cash From Operating Activities and Adjusted Funds Flow Total Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2017 compared with 2016, primarily due to a higher Operating Margin, as discussed above, partially offset by current income tax expense in 2017 compared with a recovery in 2016 and a rise in finance costs primarily associated with additional debt incurred to finance the Acquisition. The change in non-cash working capital in the fourth quarter of 2017 was primarily due to an increase in accounts payable and income tax payable, partially offset by an increase in accounts receivable and inventory. For 2016, the change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory, partially offset by an increase in accounts payable. Operating Earnings (Loss) Operating Earnings December 31, 2017 compared with 2016. Higher Cash From Operating Activities and Adjusted Funds Flow, as discussed above, was more than offset by exploration expense of $887 million, and an increase in DD&A as a result of the Acquisition. from continuing operations decreased $554 million in the three months ended Operating Earnings from discontinued operations of $19 million decreased $281 million in the three months ended December 31, 2017 compared with 2016 due to a decrease in production volumes and operating margin, as discussed above. In addition, 2016 included an impairment reversal of $462 million which arose primarily due to the increase in our Northern Alberta CGU’s estimated recoverable amount caused by a reduction in expected average future operating costs and lower future development costs, partially offset by a decline in estimated reserves. Net Earnings (Loss) Net loss from continuing operations for the three months ended December 31, 2017 increased $567 million compared with 2016. The increase in net loss was primarily due to lower operating earnings, as discussed above, and unrealized risk management losses of $654 million compared with $114 million in 2016, partially offset by non-operating unrealized foreign exchange losses of $51 million compared with $152 million in 2016. In addition, a deferred tax recovery of $275 million was recorded to reflect the benefit of the decreased U.S. federal corporate income tax rate. Net earnings from discontinued operations in the fourth quarter includes a $1,378 million after-tax gain on the divestiture of our Conventional segment assets. Capital Investment Capital investment from continuing operations in the fourth quarter of 2017 was $557 million, an increase of $355 million from 2016. The increase was primarily due to the drilling and completion of horizontal production wells within the Deep Basin corridor. Capital investment from discontinued operations was down 54 percent to $26 million in the fourth quarter of 2017 compared with 2016 due to reduced spending as a result of the decision to divest our legacy Conventional assets in first and second quarters of 2017. 2017 ANNUAL REPORT | 35 OIL AND GAS RESERVES Reconciliation of Probable Reserves We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil, NGLs, conventional natural gas and shale gas proved and probable reserves. Developments in 2017 compared with 2016 include: • Bitumen proved reserves increasing 103 percent primarily due to the acquisition of the remaining 50 percent working interest in FCCL. In addition, 169 million barrels of proved reserves were added at Foster Creek and Narrows Lake as a result of the Alberta Energy Regulator’s (the “AER”) approval of expansions converting probable reserves to proved reserves, and from improved reservoir performance; Proved plus probable bitumen reserves increasing 92 percent as the acquisition of the remaining 50 percent working interest in FCCL was partially offset by the Grand Rapids divestiture; • • Heavy oil proved reserves declining 87 percent and heavy oil proved plus probable reserves declining 86 percent primarily due to the divestiture of Pelican Lake; • Both light and medium oil proved reserves and proved plus probable reserves decreasing 87 percent, primarily as a result of the Palliser and Weyburn dispositions; • NGLs proved and probable reserves increasing 101 million barrels and 67 million barrels, respectively, due to the acquisition of the Deep Basin Assets; • Conventional natural gas proved reserves increased by 1,175 billion cubic feet and conventional natural gas probable reserves increased by 648 billion cubic feet as the acquisition of the Deep Basin Assets more than offset the Palliser disposition; and • Shale gas proved and proved plus probable reserves of 283 billion cubic feet and 568 billion cubic feet, respectively, were booked as a result of the acquisition of the Deep Basin Assets. The reserves data that follows is presented as at December 31, 2017 using an average of forecasts (“IQRE Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. The IQRE Average Forecast prices and inflation is dated January 1, 2018. Comparative information as at December 31, 2016 uses McDaniel’s January 1, 2017 forecast prices and inflation. Reserves As at December 31, 2017 (before royalties) (1) Proved Probable Proved plus Probable Heavy Oil (MMbbls) Light & Medium Oil (MMbbls) 15 12 27 13 6 19 Conventional Natural Gas (Bcf) 1,827 860 2,687 NGLs (MMbbls) 103 68 171 Bitumen (MMbbls) 4,750 1,633 6,383 Shale Gas (Bcf) 283 285 568 Total (MMBOE) 5,232 1,910 7,142 (1) Includes reserves associated with the Suffield asset sold January 5, 2018, representing before royalties 69 MMBOE and 82 MMBOE on a proved and proved plus probable basis, respectively. Reconciliation of Proved Reserves (before royalties) December 31, 2016 Extensions and Improved Recovery Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production (2) December 31, 2017 Year Over Year Change Bitumen (MMbbls) Heavy Oil (MMbbls) Light & Medium Oil (MMbbls) NGLs (MMbbls) Conventional Natural Gas (1) (Bcf) Shale Gas (Bcf) Total (MMBOE) 2,343 141 - 28 - 2,345 - (107) 4,750 2,407 103% 114 - 2 2 - - (95) (8) 15 (99) 99 - - - - 14 (90) (10) 13 (86) 2 1 - - - 108 (2) (6) 103 101 (87)% (87)% 5,050% 652 35 - 86 - 1,557 (266) (237) 1,827 1,175 180% - - - - - 289 - (6) 283 283 -% 2,667 148 2 43 - 2,775 (231) (172) 5,232 2,565 96% (1) (2) Includes coal bed methane (“CBM”) as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions. Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production. Extensions and Improved Recovery (before royalties) December 31, 2016 Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production December 31, 2017 Year Over Year Change Light & Medium Heavy Oil Bitumen (MMbbls) (MMbbls) (MMbbls) (MMbbls) Oil NGLs Conventional Natural Gas (1) (Bcf) Shale Gas (Bcf) Total (MMBOE) 976 (141) (10) 887 (79) - - - 1,633 657 67% 75 43 - 7 - - - - - - - - 6 - 6 (70) (43) 12 (63) (37) (84)% (86)% 6,700% 1 3 - - - 65 (1) - 68 67 212 21 (3) 748 (118) - - - 860 648 306% 15 - - - - - - 270 285 285 -% 1,130 (132) (10) 1,128 (213) 7 - - 1,910 780 69% (1) Includes CBM as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions. Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) is contained in our AIF for the year ended December 31, 2017. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this MD&A in the “Risk Management and Risk Factors” section. LIQUIDITY AND CAPITAL RESOURCES ($ millions) Cash From (Used In) Operating Activities – Continuing Operations Operating Activities – Discontinued Operations Total Operating Activities Investing Activities – Continuing Operations Investing Activities – Discontinued Operations Total Investing Activities Net Cash Provided (Used) Before Financing Activities Financing Activities Foreign Currency Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Increase (Decrease) in Cash and Cash Equivalents As at December 31, Cash and Cash Equivalents Committed and Undrawn Credit Facility Cash From (Used In) Operating Activities 2017 2016 2015 2,611 448 3,059 (15,859) 2,993 (12,866) (9,807) 6,515 182 (3,110) 2017 610 4,500 426 435 861 (911) (168) (1,079) (218) (168) 1 (385) 2016 3,720 4,000 696 778 1,474 1,131 (243) 888 2,362 894 (34) 3,222 2015 4,105 4,000 Cash From Operating Activities increased in 2017 mainly due to higher Operating Margin, as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held for sale, and the current portion of the contingent payment, our working capital was $1,133 million at December 31, 2017 compared with $4,423 million at December 31, 2016. Working capital declined primarily due to the use of cash and cash equivalents to fund the Acquisition. We anticipate that we will continue to meet our payment obligations as they come due. Cash From (Used In) Investing Activities In 2017, the increase in cash used in investing activities was primarily due to the Acquisition and an increase in capital investment, partially offset by $3.2 billion in proceeds from the divestiture of our legacy Conventional assets. In 2016, capital investment was limited due to spending reductions in response to the low commodity price environment. 36 | CENOVUS ENERGY OIL AND GAS RESERVES Reconciliation of Probable Reserves We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil, NGLs, conventional natural gas and shale gas proved and probable reserves. Developments in 2017 compared with 2016 include: • Bitumen proved reserves increasing 103 percent primarily due to the acquisition of the remaining 50 percent working interest in FCCL. In addition, 169 million barrels of proved reserves were added at Foster Creek and Narrows Lake as a result of the Alberta Energy Regulator’s (the “AER”) approval of expansions converting probable reserves to proved reserves, and from improved reservoir performance; • Proved plus probable bitumen reserves increasing 92 percent as the acquisition of the remaining 50 percent working interest in FCCL was partially offset by the Grand Rapids divestiture; • Heavy oil proved reserves declining 87 percent and heavy oil proved plus probable reserves declining 86 percent primarily due to the divestiture of Pelican Lake; • Both light and medium oil proved reserves and proved plus probable reserves decreasing 87 percent, primarily as a result of the Palliser and Weyburn dispositions; • NGLs proved and probable reserves increasing 101 million barrels and 67 million barrels, respectively, due to the acquisition of the Deep Basin Assets; • Conventional natural gas proved reserves increased by 1,175 billion cubic feet and conventional natural gas probable reserves increased by 648 billion cubic feet as the acquisition of the Deep Basin Assets more than offset the Palliser disposition; and • Shale gas proved and proved plus probable reserves of 283 billion cubic feet and 568 billion cubic feet, respectively, were booked as a result of the acquisition of the Deep Basin Assets. The reserves data that follows is presented as at December 31, 2017 using an average of forecasts (“IQRE Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. The IQRE Average Forecast prices and inflation is dated January 1, 2018. Comparative information as at December 31, 2016 uses McDaniel’s January 1, 2017 forecast prices and inflation. Light & Medium Heavy Oil (MMbbls) (MMbbls) (MMbbls) Oil NGLs Conventional Natural 15 12 27 13 6 19 103 68 171 Gas (Bcf) 1,827 860 2,687 Shale Gas (Bcf) 283 285 568 Total (MMBOE) 5,232 1,910 7,142 Bitumen (MMbbls) 4,750 1,633 6,383 (1) Includes reserves associated with the Suffield asset sold January 5, 2018, representing before royalties 69 MMBOE and 82 MMBOE on a proved and Reserves As at December 31, 2017 (before royalties) (1) Proved Probable Proved plus Probable proved plus probable basis, respectively. Reconciliation of Proved Reserves Extensions and Improved Recovery (before royalties) December 31, 2016 Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production (2) December 31, 2017 Year Over Year Change Light & Medium Heavy Oil Bitumen (MMbbls) (MMbbls) (MMbbls) (MMbbls) Oil NGLs Conventional Natural Gas (1) (Bcf) Shale Gas (Bcf) Total (MMBOE) 2,343 141 28 - - - 2,345 (107) 4,750 2,407 103% 114 99 - 2 2 - - (95) (8) 15 (99) - - - - 14 (90) (10) 13 (86) 2 1 - - - 108 (2) (6) 103 101 (87)% (87)% 5,050% 652 35 86 - - 1,557 (266) (237) 1,827 1,175 180% - - - - - - 289 (6) 283 283 -% 2,667 148 2 43 - 2,775 (231) (172) 5,232 2,565 96% (1) (2) Includes coal bed methane (“CBM”) as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions. Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production. (before royalties) December 31, 2016 Extensions and Improved Recovery Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production December 31, 2017 Year Over Year Change Bitumen (MMbbls) Heavy Oil (MMbbls) Light & Medium Oil (MMbbls) NGLs (MMbbls) Conventional Natural Gas (1) (Bcf) Shale Gas (Bcf) Total (MMBOE) 976 (141) - (10) - 887 (79) - 1,633 657 67% 75 - 7 - - - (70) - 12 (63) 43 - - - - 6 (43) - 6 (37) 1 3 - - - 65 (1) - 68 67 212 21 - (3) - 748 (118) - 860 648 (84)% (86)% 6,700% 306% - 15 - - - 270 - - 285 285 -% 1,130 (132) 7 (10) - 1,128 (213) - 1,910 780 69% (1) Includes CBM as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions. Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) is contained in our AIF for the year ended December 31, 2017. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this MD&A in the “Risk Management and Risk Factors” section. LIQUIDITY AND CAPITAL RESOURCES ($ millions) Cash From (Used In) Operating Activities – Continuing Operations Operating Activities – Discontinued Operations Total Operating Activities Investing Activities – Continuing Operations Investing Activities – Discontinued Operations Total Investing Activities Net Cash Provided (Used) Before Financing Activities Financing Activities Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency Increase (Decrease) in Cash and Cash Equivalents As at December 31, Cash and Cash Equivalents Committed and Undrawn Credit Facility Cash From (Used In) Operating Activities 2017 2016 2015 2,611 448 3,059 (15,859) 2,993 (12,866) (9,807) 6,515 182 (3,110) 2017 610 4,500 426 435 861 (911) (168) (1,079) (218) (168) 1 (385) 2016 3,720 4,000 696 778 1,474 1,131 (243) 888 2,362 894 (34) 3,222 2015 4,105 4,000 Cash From Operating Activities increased in 2017 mainly due to higher Operating Margin, as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held for sale, and the current portion of the contingent payment, our working capital was $1,133 million at December 31, 2017 compared with $4,423 million at December 31, 2016. Working capital declined primarily due to the use of cash and cash equivalents to fund the Acquisition. We anticipate that we will continue to meet our payment obligations as they come due. Cash From (Used In) Investing Activities In 2017, the increase in cash used in investing activities was primarily due to the Acquisition and an increase in capital investment, partially offset by $3.2 billion in proceeds from the divestiture of our legacy Conventional assets. In 2016, capital investment was limited due to spending reductions in response to the low commodity price environment. 2017 ANNUAL REPORT | 37 We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. We define Capitalization as Net Debt plus Shareholders’ Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense, DD&A, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, and other income (loss), net, calculated on a trailing 12-month basis. These measures are used to steward our overall debt position and as measures of our overall financial strength. Over the long term, we target a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within the economic cycle, we expect this ratio may periodically be above the target. We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in our committed credit facility The following is a reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA: agreement. As at December 31, Long-Term Debt Less: Cash and Cash Equivalents Net Debt Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income DD&A E&E Impairment Income Tax (Recovery) Expense Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation Gain Re-measurement of Contingent Payment (Gain) Loss on Discontinuance (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Adjusted EBITDA (1) Net Debt to Adjusted EBITDA As at December 31, Net Debt Shareholders’ Equity Capitalization Net Debt to Capitalization (1) 2017 9,513 (610) 8,903 3,366 725 (62) 352 2,030 890 729 (812) (2,555) (138) (1,285) 1 (5) 3,236 2.8x 2017 8,903 19,981 28,884 31% 2016 6,332 (3,720) 2,612 (545) 492 (52) (382) 1,498 554 (198) 2 - - - 6 34 1,409 1.9x 2016 2,612 11,590 14,202 18% 2015 6,525 (4,105) 2,420 618 482 (28) (81) 2,114 138 195 1,036 - - - 2 (2,392) 2,084 1.2x 2015 2,420 12,391 14,811 16% Cash From (Used In) Financing Activities Financial Metrics Cash from financing activities increased in 2017 primarily due to the issuance of debt and common shares to help finance the Acquisition. Total debt as at December 31, 2017 was $9,513 million (December 31, 2016 – $6,332 million), with no principal payments due until October 15, 2019 (US$1.3 billion). The increase in total debt is primarily due to the Acquisition financing. As at December 31, 2017, we were in compliance with all of the terms of our debt agreements. Senior Unsecured Notes In connection with the Acquisition, we completed an offering in the U.S. on April 7, 2017 for US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017, we completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged for notes registered under the U.S. Securities Act of 1933 with essentially the same terms and provisions as the 2017 Notes. Committed Bridge Facility On May 17, 2017, concurrent with the close of the Acquisition, we borrowed $3.6 billion under a committed Bridge Facility. The committed Bridge Facility was repaid in full, using the proceeds from divestiture of our legacy Conventional assets as well as cash on hand, and retired prior to December 31, 2017. Common Shares In connection with the Acquisition, on April 6, 2017, Cenovus closed a bought-deal common share offering for 187.5 million common shares for gross proceeds of $3.0 billion. Dividends In 2017, we paid dividends of $0.20 per share or $225 million (2016 – $0.20 per share or $166 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly. Available Sources of Liquidity We expect cash flows from our liquids, natural gas and refining operations to fund all of our cash requirements in 2018. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity, management of our asset portfolio and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and Fitch Ratings. The following sources of liquidity are available at December 31, 2017: (1) Calculated on a trailing 12-month basis. Includes discontinued operations. ($ millions) Cash and Cash Equivalents Committed Credit Facility – Tranche A Committed Credit Facility – Tranche B Committed Credit Facility Term Amount Net Debt to Capitalization is calculated as follows: Not applicable November 2021 November 2020 610 3,300 1,200 On April 28, 2017, we amended our existing committed credit facility to increase the capacity by $0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and $3.3 billion tranche maturing on November 30, 2021. As of December 31, 2017, no amounts were drawn on our committed credit facility. Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed 65 percent; we are well below this limit. Base Shelf Prospectus On October 10, 2017, we filed a base shelf prospectus that allows us to offer, from time to time, up to US$7.5 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere, where permitted by law. The base shelf prospectus is available to ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019 and replaced our US$5.0 billion base shelf prospectus, which would have expired in March 2018. Offerings under the base shelf prospectus are subject to market conditions. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion remains available under the base shelf prospectus. (1) Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity. As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8x, which is above our target. However, it is important to note that Adjusted EBITDA is calculated on a trailing 12-month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to December 31, 2017. Net debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower. Net Debt to Adjusted EBITDA increased as a result of a higher long-term debt balance, partially offset by higher Adjusted EBITDA due to the rise in sales volumes as a result of the Acquisition and higher commodity prices. Net Debt to Capitalization increased as a result of the higher long-term debt balance, related to the Acquisition, partially offset by the increase in Shareholders’ Equity and the strengthening of the Canadian dollar relative to the U.S. dollar. Consolidated Financial Statements. Additional information regarding our financial measures and capital structure can be found in the notes to the 38 | CENOVUS ENERGY Cash from financing activities increased in 2017 primarily due to the issuance of debt and common shares to help Total debt as at December 31, 2017 was $9,513 million (December 31, 2016 – $6,332 million), with no principal payments due until October 15, 2019 (US$1.3 billion). The increase in total debt is primarily due to the Acquisition As at December 31, 2017, we were in compliance with all of the terms of our debt agreements. finance the Acquisition. financing. Senior Unsecured Notes In connection with the Acquisition, we completed an offering in the U.S. on April 7, 2017 for US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017, we completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged for notes registered under the U.S. Securities Act of 1933 with essentially the same terms and provisions as the 2017 Notes. Committed Bridge Facility Common Shares Dividends On May 17, 2017, concurrent with the close of the Acquisition, we borrowed $3.6 billion under a committed Bridge Facility. The committed Bridge Facility was repaid in full, using the proceeds from divestiture of our legacy Conventional assets as well as cash on hand, and retired prior to December 31, 2017. In connection with the Acquisition, on April 6, 2017, Cenovus closed a bought-deal common share offering for 187.5 million common shares for gross proceeds of $3.0 billion. In 2017, we paid dividends of $0.20 per share or $225 million (2016 – $0.20 per share or $166 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly. Available Sources of Liquidity We expect cash flows from our liquids, natural gas and refining operations to fund all of our cash requirements in 2018. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity, management of our asset portfolio and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and Fitch Ratings. ($ millions) Cash and Cash Equivalents Committed Credit Facility – Tranche A Committed Credit Facility – Tranche B Committed Credit Facility On April 28, 2017, we amended our existing committed credit facility to increase the capacity by $0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and $3.3 billion tranche maturing on November 30, 2021. As of December 31, 2017, no amounts were drawn on our committed credit facility. Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed 65 percent; we are well below this limit. Base Shelf Prospectus On October 10, 2017, we filed a base shelf prospectus that allows us to offer, from time to time, up to US$7.5 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere, where permitted by law. The base shelf prospectus is available to ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019 and replaced our US$5.0 billion base shelf prospectus, which would have expired in March 2018. Offerings under the base shelf prospectus are subject to market conditions. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion remains available under the base shelf prospectus. Cash From (Used In) Financing Activities Financial Metrics We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. We define Capitalization as Net Debt plus Shareholders’ Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense, DD&A, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, and other income (loss), net, calculated on a trailing 12-month basis. These measures are used to steward our overall debt position and as measures of our overall financial strength. Over the long term, we target a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within the economic cycle, we expect this ratio may periodically be above the target. We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in our committed credit facility agreement. The following is a reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA: As at December 31, Long-Term Debt Less: Cash and Cash Equivalents Net Debt Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income Income Tax (Recovery) Expense DD&A E&E Impairment Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation Gain Re-measurement of Contingent Payment (Gain) Loss on Discontinuance (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Adjusted EBITDA (1) Net Debt to Adjusted EBITDA The following sources of liquidity are available at December 31, 2017: (1) Calculated on a trailing 12-month basis. Includes discontinued operations. Term Amount Net Debt to Capitalization is calculated as follows: Not applicable November 2021 November 2020 610 3,300 1,200 As at December 31, Net Debt Shareholders’ Equity Capitalization Net Debt to Capitalization (1) 2017 9,513 (610) 8,903 3,366 725 (62) 352 2,030 890 729 (812) (2,555) (138) (1,285) 1 (5) 3,236 2.8x 2017 8,903 19,981 28,884 31% 2016 6,332 (3,720) 2,612 (545) 492 (52) (382) 1,498 2 554 (198) - - - 6 34 1,409 1.9x 2016 2,612 11,590 14,202 18% 2015 6,525 (4,105) 2,420 618 482 (28) (81) 2,114 138 195 1,036 - - - (2,392) 2 2,084 1.2x 2015 2,420 12,391 14,811 16% (1) Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity. As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8x, which is above our target. However, it is important to note that Adjusted EBITDA is calculated on a trailing 12-month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to December 31, 2017. Net debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower. Net Debt to Adjusted EBITDA increased as a result of a higher long-term debt balance, partially offset by higher Adjusted EBITDA due to the rise in sales volumes as a result of the Acquisition and higher commodity prices. Net Debt to Capitalization increased as a result of the higher long-term debt balance, related to the Acquisition, partially offset by the increase in Shareholders’ Equity and the strengthening of the Canadian dollar relative to the U.S. dollar. Additional information regarding our financial measures and capital structure can be found in the notes to the Consolidated Financial Statements. 2017 ANNUAL REPORT | 39 Share Capital and Stock-Based Compensation Plans As at December 31, 2017, there were approximately 1,229 million common shares outstanding (2016 – 833 million common shares). In connection with the Acquisition, Cenovus closed a bought-deal common share financing on April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs). In addition, we issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with management recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these shares. As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance Share Unit (“PSU”) Plan, a Restricted Share Unit (“RSU”) Plan and two Deferred Share Unit (“DSU”) Plans. Certain directors, officers or employees chose prior to December 31, 2017 to convert a portion of their remuneration, paid in the first quarter of 2018, into DSUs. The election for any particular year is irrevocable. DSUs may not be redeemed until after departure from Cenovus. Directors also received an annual grant of DSUs. Refer to Note 29 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans. As at January 31, 2018 Common Shares Stock Options Other Stock-Based Compensation Plans Contractual Obligations and Commitments Units Outstanding (thousands) Units Exercisable (thousands) 1,228,790 42,337 13,963 N/A 35,263 1,439 Cenovus has obligations for goods and services that were entered into in the normal course of business. Obligations are primarily related to transportation agreements, operating leases on buildings, our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less than one year are excluded. For further information, see the notes to the Consolidated Financial Statements. The items below have been grouped as operating, investing and financing, relating to the type of cash outflow that will arise. ($ millions) Operating Transportation and Storage (1) Operating Leases (Building Leases) Other Long-term Commitments Interest on Long-term Debt Decommissioning Liabilities Other Total Operating Investing Capital Commitments Total Investing Financing Long-term Debt (principal only) Other Total Financing Total Payments (2) (3) 2018 2019 2020 2021 2022 Thereafter Total Expected Payment Date 899 155 109 494 23 11 1,691 16 16 - - - 1,707 886 146 39 494 41 11 1,617 2 2 1,631 - 1,631 3,250 919 142 32 402 45 9 1,549 - - - 1 1 1,550 1,123 141 28 401 43 5 1,741 - - - - - 1,741 1,223 140 25 401 35 4 1,828 - - 627 1 628 2,456 13,260 2,305 122 5,970 1,717 14 23,388 18,310 3,029 355 8,162 1,904 54 31,814 - - 18 18 7,339 2 7,341 30,729 9,597 4 9,601 41,433 (1) (2) (3) Includes transportation commitments of $9 billion that are subject to regulatory approval or have been approved but are not yet in service. Contracts on behalf of WRB Refining LP (“WRB”) are reflected at our 50 percent interest. Total commitments as at December 31, 2017 includes $29 million related to the Suffield assets that were divested on January 5, 2018. Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement. We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. We continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil. 40 | CENOVUS ENERGY As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for performance under certain contracts (December 31, 2016 – $258 million). We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements. Legal Proceedings Contingent Payment In connection with the Acquisition and related to oil sands production, we agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. As at December 31, 2017, the estimated fair value of the contingent payment was $206 million. WCS averaged above $52 per barrel in the fourth quarter of 2017; therefore, $17 million is payable under this agreement. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further. See the Corporate and Eliminations section of this MD&A for more details. RISK MANAGEMENT AND RISK FACTORS Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition, results of operations and cash flows, which may reduce or restrict our ability to pay a dividend to our shareholders and may materially affect the market price of our securities. Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of risk across Cenovus and is integrated with the Cenovus Operations Management System (“COMS”). In addition, we continuously monitor our risk profile as well as industry best practices. Risk Governance The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Building on the ERM Policy, we have established Risk Management Practices, a Risk Management Framework and Risk Assessment Tools. Our Risk Management Framework contains the key attributes recommended by the International Standards Organization (“ISO”) in its ISO 31000 – Risk Management Principles and Guidelines. The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as through quarterly updates. Risk Assessment All risks are assessed for their potential impact on the achievement of Cenovus’s strategic objectives as well as their likelihood of occurring. Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment tools and each risk is classified on a continuum ranging from “Low” to “Extreme”. Management determines what, if any, additional risk treatment is required based on the residual risk ranking. There are prescribed actions for escalating and communicating risk to the right decision makers. The following discussion describes the financial, operational, regulatory, environmental, reputational and other risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks, have a material impact on our business, financial condition, results of operations, cash flows, or reputation. Significant Risk Factors Financial Risk Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions. Financial risks include, but are not limited to: fluctuations in commodity prices; development and operating costs; risks related to Cenovus’s hedging activities; exposure to counterparties; availability of capital and access to sufficient liquidity; risks related to Cenovus’s credit ratings; fluctuations in foreign exchange and interest rates; and risks related to our ability to pay a dividend to shareholders. Changes in any of these economic conditions could impact a number of factors including, but not limited to, Cenovus’s cash flows, financial condition, results of Share Capital and Stock-Based Compensation Plans As at December 31, 2017, there were approximately 1,229 million common shares outstanding (2016 – 833 million common shares). In connection with the Acquisition, Cenovus closed a bought-deal common share financing on April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs). In addition, we issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with management recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these shares. As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance Share Unit (“PSU”) Plan, a Restricted Share Unit (“RSU”) Plan and two Deferred Share Unit (“DSU”) Plans. Certain directors, officers or employees chose prior to December 31, 2017 to convert a portion of their remuneration, paid in the first quarter of 2018, into DSUs. The election for any particular year is irrevocable. DSUs may not be redeemed until after departure from Cenovus. Directors also received an annual grant of DSUs. Refer to Note 29 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans. As at January 31, 2018 Common Shares Stock Options Other Stock-Based Compensation Plans Contractual Obligations and Commitments Units Outstanding (thousands) Units Exercisable (thousands) 1,228,790 42,337 13,963 N/A 35,263 1,439 Cenovus has obligations for goods and services that were entered into in the normal course of business. Obligations are primarily related to transportation agreements, operating leases on buildings, our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less than one year are excluded. For further information, see the notes to the Consolidated Financial Statements. The items below have been grouped as operating, investing and financing, relating to the type of cash outflow that will arise. ($ millions) Operating Transportation and Storage (1) Operating Leases (Building Leases) Other Long-term Commitments Interest on Long-term Debt Decommissioning Liabilities Other Total Operating Investing Capital Commitments Total Investing Financing Other Total Financing Total Payments (2) (3) Long-term Debt (principal only) 2018 2019 2020 2021 2022 Thereafter Total Expected Payment Date 1,691 1,617 1,549 1,741 1,828 23,388 31,814 899 155 109 494 23 11 16 16 - - - 886 146 39 494 41 11 2 2 - 1,631 1,631 3,250 1,123 1,223 919 142 32 402 45 9 - - - 1 1 141 28 401 43 5 - - - - - 140 25 401 35 4 - - 627 1 628 18,310 3,029 355 8,162 1,904 54 18 18 13,260 2,305 122 5,970 1,717 14 - - 2 7,339 9,597 7,341 30,729 4 9,601 41,433 (1) (2) (3) Includes transportation commitments of $9 billion that are subject to regulatory approval or have been approved but are not yet in service. Contracts on behalf of WRB Refining LP (“WRB”) are reflected at our 50 percent interest. Total commitments as at December 31, 2017 includes $29 million related to the Suffield assets that were divested on January 5, 2018. 1,707 1,550 1,741 2,456 Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement. We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. We continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil. As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for performance under certain contracts (December 31, 2016 – $258 million). Legal Proceedings We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements. Contingent Payment In connection with the Acquisition and related to oil sands production, we agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. As at December 31, 2017, the estimated fair value of the in the fourth quarter of 2017; contingent payment was $206 million. WCS averaged above $52 per barrel therefore, $17 million is payable under this agreement. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further. See the Corporate and Eliminations section of this MD&A for more details. RISK MANAGEMENT AND RISK FACTORS Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition, results of operations and cash flows, which may reduce or restrict our ability to pay a dividend to our shareholders and may materially affect the market price of our securities. Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of risk across Cenovus and is integrated with the Cenovus Operations Management System (“COMS”). In addition, we continuously monitor our risk profile as well as industry best practices. Risk Governance The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Building on the ERM Policy, we have established Risk Management Practices, a Risk Management Framework and Risk Assessment Tools. Our Risk Management Framework the key attributes recommended by the International Standards Organization (“ISO”) in its ISO 31000 – Risk Management Principles and Guidelines. The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as through quarterly updates. contains Risk Assessment ERM Policy Cenovus Risk Management Framework Risk Practices, Systems And Manuals Risk Assessment Procedures, Processes And Tools Risk Limits And Controls All risks are assessed for their potential impact on the achievement of Cenovus’s strategic objectives as well as their likelihood of occurring. Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment tools and each risk is classified on a continuum ranging from “Low” to “Extreme”. Management determines what, if any, additional risk treatment is required based on the residual risk ranking. There are prescribed actions for escalating and communicating risk to the right decision makers. Significant Risk Factors The following discussion describes the financial, operational, regulatory, environmental, reputational and other risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks, have a material impact on our business, financial condition, results of operations, cash flows, or reputation. Financial Risk Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions. Financial risks include, but are not limited to: fluctuations in commodity prices; development and operating costs; risks related to Cenovus’s hedging activities; exposure to counterparties; availability of capital and access to sufficient liquidity; risks related to Cenovus’s credit ratings; fluctuations in foreign exchange and interest rates; and risks related to our ability to pay a dividend to shareholders. Changes in any of these economic conditions could impact a number of factors including, but not limited to, Cenovus’s cash flows, financial condition, results of 2017 ANNUAL REPORT | 41 operations and growth, the maintenance of our existing operations, financial strength of our counterparties, access to capital and cost of borrowing. unenforceability of contracts. counterparties to transact with; counterparty default; deficiency in systems or controls; human error; and the Commodity Prices Our financial performance is significantly dependent on the prevailing prices of crude oil, natural gas and refined products. Crude oil prices are impacted by a number of factors including, but not limited to: the supply of and demand for crude oil; global economic conditions; the actions of OPEC including, without limitation, compliance or non-compliance with quotas agreed upon by OPEC members and decisions by OPEC not to impose production quotas on its members; enforcement of government or environmental regulations; political stability; market access constraints and transportation interruptions (pipeline, marine or rail); the availability of alternate fuel sources; and weather conditions. Natural gas prices are impacted by a number of factors including, but not limited to: North American supply and demand; developments related to the market for liquefied natural gas; weather conditions; prices of alternate sources of energy; government or environmental regulations; and economic conditions. Refined product prices are impacted by a number of factors including, but not limited to: global supply and demand for refined products; market competitiveness; levels of refined product inventories; refinery availability; planned and unplanned refinery maintenance; weather conditions; and the availability of alternate fuel sources. All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars. Our financial performance is also impacted by discounted or reduced commodity prices for our oil production relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell products to international markets and the quality of oil produced. Of particular importance to us are diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy crude oil. Bitumen is more expensive for refineries to process and therefore trades at a discount to the market price for light and medium crude oil and heavy crude oil. The financial performance of our refining operations is impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production changes to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact on our business. Fluctuations in the price of commodities, associated price differentials and refining margins may impact the value of our assets, our cash flows, our ability to maintain our business and to fund growth projects including, but not limited to, the continued development of our oil sands properties. Prolonged periods of commodity price volatility may also negatively impact our ability to meet guidance targets and meet all of our financial obligations as they come due. Any substantial decline in these commodity prices or extended period of low commodity prices may result in a delay or cancellation of existing or future drilling, development or construction programs, curtailment in production, unutilized long-term transportation commitments and/or low utilization levels at Cenovus’s refineries. The commodity price risks noted above, as well as the other risks such as market access constraints and transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully described herein, that may have a material impact on our business, financial condition, results of operations, cash flows or reputation, may be considered to be indicators of impairment. Another indication of impairment is the comparison of the carrying value of our assets to our market capitalization. As discussed in this MD&A, we conduct an annual assessment of the carrying value of our assets in accordance with IFRS. If crude oil and natural gas prices decline significantly and remain at low levels for an extended period of time, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected. Development and Operating Costs Our financial performance is significantly affected by the cost of developing and operating our assets. Development and operating costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies; inflationary price pressure; scheduling delays; failure to maintain quality construction and manufacturing standards; and supply chain disruptions, including access to skilled labour. Electricity, water, diluent, chemicals, supplies, reclamation, abandonment and labour costs are examples of operating costs that are susceptible to significant fluctuation. Hedging Activities Cenovus’s Market Risk Mitigation Policy, which has been approved by the Board, allows Management to use derivative instruments to help mitigate the impact of changes in oil and natural gas prices, diluent or condensate supply prices, refining margins, power prices, as well as fluctuations in foreign exchange rates and interest rates. Cenovus also uses derivative instruments in various operational markets to help optimize our supply cost or sales. The use of such hedging activities exposes us to risks which may cause significant loss. These risks include, but are not limited to: changes in the valuation of the hedge instrument being not well correlated to the change in the valuation of the underlying exposures being hedged; change in price of the underlying commodity; insufficient 42 | CENOVUS ENERGY There is risk that the consequences of hedging to protect against unfavourable market conditions may limit the benefit to us of commodity price increases or changes in interest rates and foreign exchange rates. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil, natural gas or refined products to fulfill our delivery obligations related to the underlying physical transaction. We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts and market access commitments. Financial instruments utilized within the refining business are primarily for purchased product. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3 and 33 to the Consolidated Financial Statements. Impact of Financial Risk Management Activities ($ millions) Crude Oil (1) Refining Power Interest Rate Foreign Exchange (Gain) Loss on Risk Management Income Tax Expense (Recovery) (Gain) Loss on Risk Management, After Tax 2017 2016 Realized Unrealized Total Realized Unrealized 307 716 1,023 6 - - (146) 167 (60) 107 - - - 13 729 (197) 532 6 - 13 (146) 896 (257) 639 (152) (1) - - - (153) 39 (114) 560 5 3 - 554 (150) 404 Total 408 4 3 - 401 (111) 290 (14) (14) (1) Excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment (2016 – $58 million realized risk management gains), which has been classified as a discontinued operation. In 2017, we incurred realized losses on crude oil risk management activities, consistent with the average benchmark prices exceeding our contract prices and realized gains on foreign exchange contracts primarily due to hedging activity undertaken to support the Acquisition. Unrealized losses were recorded on our crude oil financial instruments in 2017 primarily due to the realization of settled positions and changes in market prices. Sensitivities – Risk Management Positions The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices and interest rates with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices and interest rates on risk management positions as at December 31, 2017 could have resulted in unrealized gains (losses) for the year as follows: Sensitivity Range Increase Decrease Crude Oil Commodity Price ± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production Interest Rate Swaps ± 50 Basis Points (529) 11 44 507 (11) (50) For further information on our risk management positions, see Note 34 to the Consolidated Financial Statements. Risks Associated with Derivative Financial Instruments Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Credit Policy. Exposure to Counterparties In the normal course of business, we enter into contractual relationships with suppliers, partners and other counterparties in the energy industry and other industries for the provision and sale of goods and services. If such counterparties do not fulfill their contractual obligations, we may suffer financial losses, delays of our development plans or we may have to forego other opportunities which could materially impact our financial condition or operational results. Credit, Liquidity and Availability of Future Financing The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn, a change in market fundamentals, business operations or credit rating, or significant unanticipated expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital could affect our ability to make future capital expenditures and to meet all of our financial obligations operations and growth, the maintenance of our existing operations, financial strength of our counterparties, access to capital and cost of borrowing. Commodity Prices Our financial performance is significantly dependent on the prevailing prices of crude oil, natural gas and refined products. Crude oil prices are impacted by a number of factors including, but not limited to: the supply of and demand for crude oil; global economic conditions; the actions of OPEC including, without limitation, compliance or non-compliance with quotas agreed upon by OPEC members and decisions by OPEC not to impose production quotas on its members; enforcement of government or environmental regulations; political stability; market access constraints and transportation interruptions (pipeline, marine or rail); the availability of alternate fuel sources; and weather conditions. Natural gas prices are impacted by a number of factors including, but not limited to: North American supply and demand; developments related to the market for liquefied natural gas; weather conditions; prices of alternate sources of energy; government or environmental regulations; and economic conditions. Refined product prices are impacted by a number of factors including, but not limited to: global supply and demand for refined products; market competitiveness; levels of refined product inventories; refinery availability; planned and unplanned refinery maintenance; weather conditions; and the availability of alternate fuel sources. All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars. Our financial performance is also impacted by discounted or reduced commodity prices for our oil production relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell products to international markets and the quality of oil produced. Of particular importance to us are diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy crude oil. Bitumen is more expensive for refineries to process and therefore trades at a discount to the market price for light and medium crude oil and heavy crude oil. The financial performance of our refining operations is impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production changes to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact on our business. Fluctuations in the price of commodities, associated price differentials and refining margins may impact the value of our assets, our cash flows, our ability to maintain our business and to fund growth projects including, but not limited to, the continued development of our oil sands properties. Prolonged periods of commodity price volatility may also negatively impact our ability to meet guidance targets and meet all of our financial obligations as they come due. Any substantial decline in these commodity prices or extended period of low commodity prices may result in a delay or cancellation of existing or future drilling, development or construction programs, curtailment in production, unutilized long-term transportation commitments and/or low utilization levels at Cenovus’s refineries. The commodity price risks noted above, as well as the other risks such as market access constraints and transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully described herein, that may have a material impact on our business, financial condition, results of operations, cash flows or reputation, may be considered to be indicators of impairment. Another indication of impairment is the comparison of the carrying value of our assets to our market capitalization. As discussed in this MD&A, we conduct an annual assessment of the carrying value of our assets in accordance with IFRS. If crude oil and natural gas prices decline significantly and remain at low levels for an extended period of time, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected. Development and Operating Costs susceptible to significant fluctuation. Hedging Activities Our financial performance is significantly affected by the cost of developing and operating our assets. Development and operating costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies; inflationary price pressure; scheduling delays; failure to maintain quality construction and manufacturing standards; and supply chain disruptions, including access to skilled labour. Electricity, water, diluent, chemicals, supplies, reclamation, abandonment and labour costs are examples of operating costs that are Cenovus’s Market Risk Mitigation Policy, which has been approved by the Board, allows Management to use derivative instruments to help mitigate the impact of changes in oil and natural gas prices, diluent or condensate supply prices, refining margins, power prices, as well as fluctuations in foreign exchange rates and interest rates. Cenovus also uses derivative instruments in various operational markets to help optimize our supply cost or sales. The use of such hedging activities exposes us to risks which may cause significant loss. These risks include, but are not limited to: changes in the valuation of the hedge instrument being not well correlated to the change in the valuation of the underlying exposures being hedged; change in price of the underlying commodity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; and the unenforceability of contracts. There is risk that the consequences of hedging to protect against unfavourable market conditions may limit the benefit to us of commodity price increases or changes in interest rates and foreign exchange rates. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil, natural gas or refined products to fulfill our delivery obligations related to the underlying physical transaction. We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts and market access commitments. Financial instruments utilized within the refining business are primarily for purchased product. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3 and 33 to the Consolidated Financial Statements. Impact of Financial Risk Management Activities 2017 2016 ($ millions) Realized Unrealized Total Realized Unrealized Total Crude Oil (1) Refining Power Interest Rate Foreign Exchange (Gain) Loss on Risk Management Income Tax Expense (Recovery) (Gain) Loss on Risk Management, After Tax 307 6 - - (146) 167 (60) 107 716 - - 13 - 729 (197) 532 1,023 6 - 13 (146) 896 (257) 639 (152) (1) - - - (153) 39 (114) 560 5 (14) 3 - 554 (150) 404 408 4 (14) 3 - 401 (111) 290 (1) Excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment (2016 – $58 million realized risk management gains), which has been classified as a discontinued operation. In 2017, we incurred realized losses on crude oil risk management activities, consistent with the average benchmark prices exceeding our contract prices and realized gains on foreign exchange contracts primarily due to hedging activity undertaken to support the Acquisition. Unrealized losses were recorded on our crude oil financial instruments in 2017 primarily due to the realization of settled positions and changes in market prices. Sensitivities – Risk Management Positions The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices and interest rates with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices and interest rates on risk management positions as at December 31, 2017 could have resulted in unrealized gains (losses) for the year as follows: Sensitivity Range Increase Decrease Crude Oil Commodity Price Crude Oil Differential Price Interest Rate Swaps ± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges ± US$2.50 per bbl Applied to Differential Hedges Tied to Production ± 50 Basis Points (529) 11 44 507 (11) (50) For further information on our risk management positions, see Note 34 to the Consolidated Financial Statements. Risks Associated with Derivative Financial Instruments Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Credit Policy. Exposure to Counterparties In the normal course of business, we enter into contractual relationships with suppliers, partners and other counterparties in the energy industry and other industries for the provision and sale of goods and services. If such counterparties do not fulfill their contractual obligations, we may suffer financial losses, delays of our development plans or we may have to forego other opportunities which could materially impact our financial condition or operational results. Credit, Liquidity and Availability of Future Financing The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn, a change in market fundamentals, business operations or credit rating, or significant unanticipated expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital could affect our ability to make future capital expenditures and to meet all of our financial obligations 2017 ANNUAL REPORT | 43 as they come due, potentially creating a material adverse effect on our financial condition, results of operations, ability to comply with various financial and operating covenants, credit ratings and reputation. Operational Risk Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, Cenovus may take actions such as reducing dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We mitigate our liquidity risk through the active management of cash and debt by ensuring that we have access to multiple sources of capital. We are required to comply with various financial and operating covenants under our credit facilities and the indentures governing our debt securities. We routinely review our covenants and we may make changes to development plans or dividend policy, or take alternative actions to ensure compliance. In the event that we do not comply with such covenants, our access to capital could be restricted or repayment could be accelerated. Credit Ratings Our company and our long-term and short-term debt are regularly evaluated by the credit rating agencies. Credit ratings are based on our financial and operational strength and a number of factors not entirely within our control, including conditions affecting the oil and gas industry generally, and the state of the economy. There can be no assurance that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency. A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. A failure by Cenovus to maintain current credit ratings could affect our business relationships with counterparties, operating partners and suppliers. If one or more of our credit ratings falls below certain ratings floors we may be obligated to post collateral in the form of cash, letters of credit or other financial instruments in order to establish or maintain business arrangements. Additional collateral may be required due to further downgrades below certain ratings floors. Failure to provide adequate risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated. Foreign Exchange Rates Fluctuations in foreign exchange rates may affect our results as global prices for crude oil, natural gas and refined products are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A change in the value of the Canadian dollar relative to the U.S. dollar will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas sales. In addition, we have chosen to borrow U.S. dollar long-term debt. A change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. To manage exposure to exchange rate fluctuations, we may periodically enter into transactions to mitigate our exposure. Exchange rate fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows. Interest Rates We may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings. An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded, both of which could negatively impact financial results. Additionally, we are exposed to interest rate fluctuations upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates. Ability to Pay Dividends The payment of dividends is at the discretion of the Board. Dividend payments are regularly reviewed by the Board and may be increased, reduced or suspended from time to time. Our ability to pay dividends and the actual amount of such dividends is dependent upon, among other things, financial performance, debt covenants, ability to meet financial obligations as they come due, working capital requirements, future tax obligations, future capital requirements, commodity prices and the risk factors set forth in this MD&A. Disclosure Controls and Procedures and Internal Controls over Financial Reporting Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation. 44 | CENOVUS ENERGY Operational risks are those risks that affect our ability to continue operations in the ordinary course of business. Our operations are subject to risks generally affecting the oil and gas and refining industries. To partially mitigate our risks, we have a system of standards, practices and procedures called the COMS to identify, assess and mitigate safety, operational and environmental risk across our operations. In addition to leveraging COMS, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations. Health and Safety The operation of our properties is subject to hazards of finding, recovering, transporting and processing hydrocarbons including, but not limited to: blowouts; fires; explosions; railcar incident or derailment; gaseous leaks; migration of harmful substances; oil spills; corrosion; acts of vandalism and terrorism; and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites. Any of these hazards can interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology systems, related data and control systems, cause environmental damage that may include polluting water, land or air, and may result in fines, civil suits, or criminal charges against Cenovus. cash flows. Market Access Constraints and Transportation Restrictions Our production is transported through various pipelines and our refineries are reliant on various pipelines to receive feedstock. Disruptions in, or restricted availability of, pipeline service and/or marine or rail transport, could adversely affect crude oil and natural gas sales, projected production growth, upstream or refining operations and Interruptions or restrictions in the availability of these pipeline systems may limit the ability to deliver production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our products. These interruptions and restrictions may be caused by the inability of the pipeline to operate, or they may be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. There can be no certainty that investments in new pipeline projects, which would result in an increase in long-term takeaway capacity, will be made by applicable third-party pipeline providers or that any applications to expand capacity will receive the required regulatory approval, or that any such approvals will result in the construction of the pipeline project. There is also no certainty that short-term operational constraints on the pipeline system, arising from pipeline interruption and/or increased supply of crude oil, will not occur. There is no certainty that crude-by-rail, marine transport and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, our crude-by-rail and marine shipments may be impacted by service delays, inclement weather, railcar derailment or other rail or marine transport incidents and could adversely impact crude oil sales volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal injury, loss of equipment or property, or environmental damage. In addition, new regulations, which will be phased in over time until 2025, will require tank cars used to transport crude oil to be replaced with newer, safer tank cars, or to be retrofitted to meet the same standards. The costs of complying with the new standards, or any further revised standards, will likely be passed on to rail shippers and may adversely affect our ability to transport crude-by-rail or the economics associated with rail transportation. Finally, planned or unplanned shutdowns or closures of our refinery customers may limit our ability to deliver product with negative implications on sales and cash from operating activities. On January 30, 2018, the British Columbia Minister of Environment and Climate Change Strategy announced proposed regulatory measures that would limit increases of diluted bitumen being transported through the province while an advisory panel studies if and how heavy oil can be transported safely. It is not clear at this time how or when the restrictions will be implemented, but they could have a material adverse impact on our ability to transport diluted bitumen. Insufficient transportation capacity for our production will impact our ability to efficiently access end markets. This may negatively impact our financial performance by way of higher transportation costs, wider price differentials, lower sales prices at specific locations or for specific grades of crude oil, and, in extreme situations, production curtailment. Operational Considerations Our crude oil and natural gas operations are subject to all of the risks normally incidental to: (i) the storing, transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; and (iii) the operation and development of crude oil and natural gas properties including, but not limited to: encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; explosions; blowouts; gaseous leaks; power outages; migration of harmful substances into water systems; oil spills; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or operate within established operating parameters; equipment failures and other accidents; adverse weather conditions; pollution; and other environmental risks. as they come due, potentially creating a material adverse effect on our financial condition, results of operations, Operational Risk ability to comply with various financial and operating covenants, credit ratings and reputation. Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, Cenovus may take actions such as reducing dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional We mitigate our liquidity risk through the active management of cash and debt by ensuring that we have access to equity capital. multiple sources of capital. We are required to comply with various financial and operating covenants under our credit facilities and the indentures governing our debt securities. We routinely review our covenants and we may make changes to development plans or dividend policy, or take alternative actions to ensure compliance. In the event that we do not comply with such covenants, our access to capital could be restricted or repayment could be accelerated. Credit Ratings Our company and our long-term and short-term debt are regularly evaluated by the credit rating agencies. Credit ratings are based on our financial and operational strength and a number of factors not entirely within our control, including conditions affecting the oil and gas industry generally, and the state of the economy. There can be no assurance that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency. A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. A failure by Cenovus to maintain current credit ratings could affect our business relationships with counterparties, operating partners and suppliers. If one or more of our credit ratings falls below certain ratings floors we may be obligated to post collateral in the form of cash, letters of credit or other financial instruments in order to establish or maintain business arrangements. Additional collateral may be required due to further downgrades below certain ratings floors. Failure to provide adequate risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated. Foreign Exchange Rates Fluctuations in foreign exchange rates may affect our results as global prices for crude oil, natural gas and refined products are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A change in the value of the Canadian dollar relative to the U.S. dollar will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas sales. In addition, we have chosen to borrow U.S. dollar long-term debt. A change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. To manage exposure to exchange rate fluctuations, we may periodically enter into transactions to mitigate our exposure. Exchange rate fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows. Interest Rates We may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings. An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded, both of which could negatively impact financial results. Additionally, we are exposed to interest rate fluctuations upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates. Ability to Pay Dividends The payment of dividends is at the discretion of the Board. Dividend payments are regularly reviewed by the Board and may be increased, reduced or suspended from time to time. Our ability to pay dividends and the actual amount of such dividends is dependent upon, among other things, financial performance, debt covenants, ability to meet financial obligations as they come due, working capital requirements, future tax obligations, future capital requirements, commodity prices and the risk factors set forth in this MD&A. Disclosure Controls and Procedures and Internal Controls over Financial Reporting Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation. Operational risks are those risks that affect our ability to continue operations in the ordinary course of business. Our operations are subject to risks generally affecting the oil and gas and refining industries. To partially mitigate our risks, we have a system of standards, practices and procedures called the COMS to identify, assess and mitigate safety, operational and environmental risk across our operations. In addition to leveraging COMS, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations. Health and Safety The operation of our properties is subject to hazards of finding, recovering, transporting and processing hydrocarbons including, but not limited to: blowouts; fires; explosions; railcar incident or derailment; gaseous leaks; migration of harmful substances; oil spills; corrosion; acts of vandalism and terrorism; and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites. Any of these hazards can interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology systems, related data and control systems, cause environmental damage that may include polluting water, land or air, and may result in fines, civil suits, or criminal charges against Cenovus. Market Access Constraints and Transportation Restrictions Our production is transported through various pipelines and our refineries are reliant on various pipelines to receive feedstock. Disruptions in, or restricted availability of, pipeline service and/or marine or rail transport, could adversely affect crude oil and natural gas sales, projected production growth, upstream or refining operations and cash flows. Interruptions or restrictions in the availability of these pipeline systems may limit the ability to deliver production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our products. These interruptions and restrictions may be caused by the inability of the pipeline to operate, or they may be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. There can be no certainty that investments in new pipeline projects, which would result in an increase in long-term takeaway capacity, will be made by applicable third-party pipeline providers or that any applications to expand capacity will receive the required regulatory approval, or that any such approvals will result in the construction of the pipeline project. There is also no certainty that short-term operational constraints on the pipeline system, arising from pipeline interruption and/or increased supply of crude oil, will not occur. There is no certainty that crude-by-rail, marine transport and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, our crude-by-rail and marine shipments may be impacted by service delays, inclement weather, railcar derailment or other rail or marine transport incidents and could adversely impact crude oil sales volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal injury, loss of equipment or property, or environmental damage. In addition, new regulations, which will be phased in over time until 2025, will require tank cars used to transport crude oil to be replaced with newer, safer tank cars, or to be retrofitted to meet the same standards. The costs of complying with the new standards, or any further revised standards, will likely be passed on to rail shippers and may adversely affect our ability to transport crude-by-rail or the economics associated with rail transportation. Finally, planned or unplanned shutdowns or closures of our refinery customers may limit our ability to deliver product with negative implications on sales and cash from operating activities. On January 30, 2018, the British Columbia Minister of Environment and Climate Change Strategy announced proposed regulatory measures that would limit increases of diluted bitumen being transported through the province while an advisory panel studies if and how heavy oil can be transported safely. It is not clear at this time how or when the restrictions will be implemented, but they could have a material adverse impact on our ability to transport diluted bitumen. Insufficient transportation capacity for our production will impact our ability to efficiently access end markets. This may negatively impact our financial performance by way of higher transportation costs, wider price differentials, lower sales prices at specific locations or for specific grades of crude oil, and, in extreme situations, production curtailment. Operational Considerations Our crude oil and natural gas operations are subject to all of the risks normally incidental to: (i) the storing, transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; and (iii) the operation and development of crude oil and natural gas properties including, but not limited to: encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; explosions; blowouts; gaseous leaks; power outages; migration of harmful substances into water systems; oil spills; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or operate within established operating parameters; equipment failures and other accidents; adverse weather conditions; pollution; and other environmental risks. 2017 ANNUAL REPORT | 45 Producing and refining oil requires high levels of investment and involves particular risks and uncertainties. Our oil operations are susceptible to loss of production, slowdowns, shutdowns, or restrictions on our ability to produce higher value products due to the interdependence of our component systems. Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production. Although we are not the operator of the two U.S. refineries in which we have a 50 percent interest, the refining and marketing business is subject to all of the risks inherent in the operation of refineries, terminals, pipelines and other transportation and distribution facilities including, but not limited to: loss of product; failure to follow operating procedures or operate within established operating parameters; slowdowns due to equipment failure or transportation disruptions; railcar incidents or derailments; marine transport incidents; weather; fires and/or explosions; unavailability of feedstock; and price and quality of feedstock. We do not insure against all potential occurrences and disruptions and it cannot be guaranteed that insurance will be sufficient to cover any such occurrences or disruptions. Our operations could also be interrupted by natural disasters or other events beyond our control. Reserves Replacement and Reserve Estimates Partner Risks If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including, but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary materially from estimated results. All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material. Estimates with respect to reserves that may be developed and produced in the future are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based on production history will result in variations, which may be material, in the estimated reserves. The production rate of oil and gas properties tends to decline as reserves are depleted while the associated operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on schedule; and the application of successful exploitation techniques on mature properties. Our business, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves. Cost Management Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and additional government or environmental regulations. Our inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on our financial condition, results of operations and cash flows. Competition The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas interests and the refining, distribution and marketing of petroleum products. We compete with other producers and refiners, some of which may have lower operating costs or greater resources than our company does. Competing producers may develop and implement recovery techniques and technologies which are superior to those we employ. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. 46 | CENOVUS ENERGY Companies may announce plans to enter the oil sands business, to begin production or to expand existing operations. Expansion of existing operations and development of new projects could materially increase the supply of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and increase our input costs for and constrain the supply of skilled labour and materials. Project Execution There are risks associated with the execution and operation of our upstream growth and development projects. These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy of project cost estimates; ability to finance growth; ability to source or complete strategic transactions; and the effect of changing government regulation and public expectations in relation to the impact of oil sands and conventional development on the environment. The commissioning and integration of new facilities within our existing asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows. Some of our assets are not operated by us or are held in partnership with others. Therefore, our results of operations and cash flows may be affected by the actions of third-party operators or partners. Our refining assets are held in a partnership with Phillips 66 and operated by Phillips 66. The success of the refining operations is dependent on the ability of Phillips 66 to successfully operate this business and maintain the refining assets. We rely on the judgment and operating expertise of Phillips 66 in respect of the operation of such refining assets and we also rely on Phillips 66 to provide information on the status of such refining assets and related results of operations. Phillips 66 may have objectives and interests that do not align with or may conflict with our interests. Major capital decisions affecting these refining assets require agreement between each respective partner, while certain operational decisions may be made by the operator of the assets. While we generally seek consensus with respect to major decisions concerning the direction and operation of these refining assets, no assurance can be provided that the future demands or expectations of either party relating to such assets will be satisfactorily met or met in a timely manner or at all. Unmet demands or expectations by either party or demands and expectations which are not satisfactorily met may affect our participation in the operation of such assets, our ability to obtain or maintain necessary licences or approvals or affect the timing of undertaking various activities. Technology Current SAGD technologies for the recovery of bitumen are energy intensive, requiring significant consumption of natural gas in the production of steam that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using this technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial condition, results of operations and cash flows. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured. Information Systems We rely heavily on information technology, such as computer hardware and software systems, in order to properly operate our business. In the event we are unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data. In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary business information and personal information of our employees and third parties. Despite our security measures, our information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or cyberterrorists or breaches due to employee error, malfeasance or other disruptions, including natural disasters and acts of war. Any such breach could compromise information used or stored on our systems and/or networks and, as a result, the information could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative consequences, including damage to our reputation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Leadership and Talent Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our talent. In 2017, Cenovus implemented a number of changes at the executive leadership level, including the appointment of Alex Pourbaix as President & Chief Executive Officer and as a member of the Board. We believe that these leadership changes will help Cenovus continue to evolve into a highly effective organization focused on Producing and refining oil requires high levels of investment and involves particular risks and uncertainties. Our oil operations are susceptible to loss of production, slowdowns, shutdowns, or restrictions on our ability to produce higher value products due to the interdependence of our component systems. Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production. Although we are not the operator of the two U.S. refineries in which we have a 50 percent interest, the refining and marketing business is subject to all of the risks inherent in the operation of refineries, terminals, pipelines and other transportation and distribution facilities including, but not limited to: loss of product; failure to follow operating procedures or operate within established operating parameters; slowdowns due to equipment failure or transportation disruptions; railcar incidents or derailments; marine transport incidents; weather; fires and/or explosions; unavailability of feedstock; and price and quality of feedstock. We do not insure against all potential occurrences and disruptions and it cannot be guaranteed that insurance will be sufficient to cover any such occurrences or disruptions. Our operations could also be interrupted by natural disasters or other events beyond our control. Reserves Replacement and Reserve Estimates If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including, but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary materially from estimated results. All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material. Estimates with respect to reserves that may be developed and produced in the future are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based on production history will result in variations, which may be material, in the estimated reserves. The production rate of oil and gas properties tends to decline as reserves are depleted while the associated operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on schedule; and the application of successful exploitation techniques on mature properties. Our business, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves. Cost Management operations and cash flows. Competition Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and additional government or environmental regulations. Our inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on our financial condition, results of The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas interests and the refining, distribution and marketing of petroleum products. We compete with other producers and refiners, some of which may have lower operating costs or greater resources than our company does. Competing producers may develop and implement recovery techniques and technologies which are superior to those we employ. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. Companies may announce plans to enter the oil sands business, to begin production or to expand existing operations. Expansion of existing operations and development of new projects could materially increase the supply of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and increase our input costs for and constrain the supply of skilled labour and materials. Project Execution There are risks associated with the execution and operation of our upstream growth and development projects. These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy of project cost estimates; ability to finance growth; ability to source or complete strategic transactions; and the effect of changing government regulation and public expectations in relation to the impact of oil sands and conventional development on the environment. The commissioning and integration of new facilities within our existing asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows. Partner Risks Some of our assets are not operated by us or are held in partnership with others. Therefore, our results of operations and cash flows may be affected by the actions of third-party operators or partners. Our refining assets are held in a partnership with Phillips 66 and operated by Phillips 66. The success of the refining operations is dependent on the ability of Phillips 66 to successfully operate this business and maintain the refining assets. We rely on the judgment and operating expertise of Phillips 66 in respect of the operation of such refining assets and we also rely on Phillips 66 to provide information on the status of such refining assets and related results of operations. Phillips 66 may have objectives and interests that do not align with or may conflict with our interests. Major capital decisions affecting these refining assets require agreement between each respective partner, while certain operational decisions may be made by the operator of the assets. While we generally seek consensus with respect to major decisions concerning the direction and operation of these refining assets, no assurance can be provided that the future demands or expectations of either party relating to such assets will be satisfactorily met or met in a timely manner or at all. Unmet demands or expectations by either party or demands and expectations which are not satisfactorily met may affect our participation in the operation of such assets, our ability to obtain or maintain necessary licences or approvals or affect the timing of undertaking various activities. Technology Current SAGD technologies for the recovery of bitumen are energy intensive, requiring significant consumption of natural gas in the production of steam that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using this technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial condition, results of operations and cash flows. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured. Information Systems We rely heavily on information technology, such as computer hardware and software systems, in order to properly operate our business. In the event we are unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data. In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary business information and personal information of our employees and third parties. Despite our security measures, our information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or cyberterrorists or breaches due to employee error, malfeasance or other disruptions, including natural disasters and acts of war. Any such breach could compromise information used or stored on our systems and/or networks and, as a result, the information could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative consequences, including damage to our reputation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Leadership and Talent Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our talent. In 2017, Cenovus implemented a number of changes at the executive leadership level, including the appointment of Alex Pourbaix as President & Chief Executive Officer and as a member of the Board. We believe that these leadership changes will help Cenovus continue to evolve into a highly effective organization focused on 2017 ANNUAL REPORT | 47 delivering strong returns for shareholders. Failure to align and effectively integrate the new leadership team, retain critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies could have a material adverse effect on our financial condition, results of operations and pace of growth. Litigation From time to time, we may be the subject of litigation arising out of our operations. Claims under such litigation may be material or may be indeterminate. Various types of claims may be made including, without limitation, environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, patent infringement and employment matters. The outcome of such litigation is uncertain and may materially impact our financial condition or results of operations. Moreover, unfavorable outcomes or settlements of litigation could encourage the commencement of additional litigation. We may also be subject to adverse publicity associated with such matters, regardless of whether we are ultimately found responsible. We may be required to incur significant expenses or devote significant resources in defense against any such litigation. Aboriginal Land and Rights Claims Aboriginal groups have claimed aboriginal treaty, title and rights to portions of western Canada, including British Columbia and Alberta, and such claims, if successful, could have a material negative impact on our operations or pace of growth. In 2014, the Supreme Court of Canada granted Aboriginal title over non-treaty lands, representing the first instance of such a declaration. There exist outstanding Aboriginal and treaty rights claims, which may include Aboriginal title claims, on lands where we operate. No certainty exists that any lands currently unaffected by claims brought by Aboriginal groups will remain unaffected by future claims. Recent outcomes of litigation concerning Aboriginal rights may result in increased claims and litigation activity in the future. The federal and provincial governments have a duty to consult with Aboriginal people on actions and decisions that may affect the asserted Aboriginal or treaty rights and, in certain cases, accommodate their concerns. The scope of the duty to consult by federal and provincial governments is subject to ongoing litigation. The fulfillment of the duty to consult, and where required accommodate, Aboriginal people may adversely affect our ability to, or increase the timeline to, obtain or renew, permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals. Opposition by Aboriginal groups may also negatively impact us in terms of public perception, diversion of Management’s time and resources, legal and other advisory expenses, potential blockades or other interference by third parties in our operations, or court-ordered relief impacting operations. Challenges by Aboriginal groups could adversely impact our progress and ability to explore and develop properties. In May 2016, Canada announced its support for the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). The principles and objectives of UNDRIP have also been endorsed by the Government of Alberta and the Government of British Columbia. The means of implementation of UNDRIP by government bodies are uncertain and may include an increase in consultation obligations and processes associated with project development, posing risks and creating uncertainty with respect to project regulatory approval timelines and requirements. Regulatory Risk Regulatory risk is the risk of loss or lost opportunity resulting from the introduction of, or changes in, regulatory requirements or the failure to secure regulatory approval for upstream or downstream development projects. The implementation of new regulations or the modification of existing regulations could impact our existing and planned projects as well as result in compliance costs, adversely impacting our financial condition, results of operations and cash flows. The oil and gas industry in general and our operations in particular are subject to regulation and intervention under federal, provincial, territorial, state and municipal legislation in Canada and the U.S. in matters such as, but not limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government fees; production rates; environmental protection controls; protection of certain species or lands; provincial and federal land use designations; the reduction of greenhouse gases (“GHGs”) and other emissions; the export of crude oil, natural gas and other products; the transportation of crude-by-rail or marine transport; the awarding or acquisition of exploration and production, oil sands or other interests; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possibly expropriation or cancellation of contract rights. Changes to government regulation could impact our existing and planned projects or increase capital investment or operating expenses, adversely impacting our financial condition, results of operations and cash flows. Regulatory Approvals Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that we will be able to obtain all necessary licences, permits and other approvals that may be required to carry out certain exploration and development activities on our properties. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder and Aboriginal consultation, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; habitat assessments; and other commitments or obligations. 48 | CENOVUS ENERGY Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs. Abandonment and Reclamation Cost Risk The current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta as a general rule limits each party's liability to its proportionate ownership of an asset. In the case where one joint owner becomes insolvent and is unable to fund the A&R activities, the solvent counterparties can claim the insolvent party’s share of the remediation costs against the Orphan Well Association (the “OWA”). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including Cenovus, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites in Alberta. British Columbia has a similar liability management regime. The Alberta Court of Queen’s Bench issued a decision in the case of Redwater Energy Corporation, (“Redwater”) that trustees and receivers of insolvent parties may disclaim or renounce uneconomic oil and gas assets to the AER before commencing the sales process for the insolvent party’s assets. These wells and facilities then become “orphans” to be remediated by the OWA. The Alberta Court of Appeal upheld the trial judge's decision in Redwater (“Redwater Appeal”), and the AER has been granted leave to appeal the Redwater Appeal to the Supreme Court of Canada. In response to Redwater, the AER released Bulletin 2016-16 which, among other things, implements important changes to the AER’s procedures relating to liability management ratings, licence eligibility and licence transfers. In addition, changes with respect to licence eligibility were codified in amendments to AER Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals. Among other things, Directive 067 provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that they should not be eligible to hold AER licences. The government of British Columbia has announced similar policies. The British Columbia Oil and Gas Commission is also exploring the development of a comprehensive liability management strategy, driven in part by the Redwater decision, and the proliferation of orphan sites. The imposition of timelines for inactive sites is among the measures under consideration. These changes may impact Cenovus’s ability to transfer our licences, approvals or permits, and may result in increased costs and delays or require changes to or abandonment of projects and transactions. Because of Redwater and the current economic environment, the number of orphaned wells in Alberta has increased significantly and, accordingly, the aggregate value of the A&R liabilities assumed by the OWA has increased and may continue to increase. The OWA may seek funding for such liabilities from industry participants, including Cenovus through an increase in its annual levy, further changes to regulations or other means. While the impact on Cenovus of any legislative, regulatory or policy decisions as a result of the Redwater decision and its pending appeal cannot be reliably or accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows. Royalty Regimes Our cash flows may be directly affected by changes to royalty regimes. The governments of Alberta and British Columbia receive royalties on the production of hydrocarbons from lands in which they respectively own the mineral rights. Government regulation of Crown royalties is subject to change for a number of reasons, including, among other things, political factors. Royalties are typically calculated based on benchmark prices, productivity per well, location, date of discovery, recovery method, well depth and the nature and quality of petroleum product produced. There is also a mineral tax in each province levied on hydrocarbon production from lands in which the Crown does not own the mineral rights. The potential for changes in the royalty and mineral tax regimes applicable in the provinces in which Cenovus operates creates uncertainty relating to the ability to accurately estimate future Crown burdens and could have a significant impact on our business, financial condition, results of operations and cash flows. The Government of Alberta has implemented a modernized royalty framework (the “Modernized Framework”) which applies to all conventional wells spud on or after January 1, 2017. The Modernized Framework does not apply to oil sands production, which has its own separate royalty framework. Wells spud prior to July 13, 2016 will continue to operate under the previous royalty framework. Wells spud between such dates may elect to opt-in to the Modernized Framework if certain criteria are met. After December 31, 2026, all wells will be subject to the Modernized Framework. As part of the Modernized Framework, the Alberta government announced two new strategic royalty programs to encourage oil and gas producers to boost production and explore resources in new areas: the Enhanced Hydrocarbon Recovery Program and the Emerging Resources Program. These programs will take into account the higher costs associated with development of emerging resources and enhanced recovery methods when calculating royalty rates. The royalty structure and rates for oil sands production in Alberta remain generally unchanged following the royalty review. The Government of Alberta has indicated that it plans to modernize the process of calculating costs and collecting oil sands royalties, and has recently implemented public disclosure of cost, revenue and collection information relating to oil sands projects and royalties. delivering strong returns for shareholders. Failure to align and effectively integrate the new leadership team, retain critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies could have a material adverse effect on our financial condition, results of operations and pace of growth. Litigation From time to time, we may be the subject of litigation arising out of our operations. Claims under such litigation may be material or may be indeterminate. Various types of claims may be made including, without limitation, environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, patent infringement and employment matters. The outcome of such litigation is uncertain and may materially impact our financial condition or results of operations. Moreover, unfavorable outcomes or settlements of litigation could encourage the commencement of additional litigation. We may also be subject to adverse publicity associated with such matters, regardless of whether we are ultimately found responsible. We may be required to incur significant expenses or devote significant resources in defense against any such litigation. Aboriginal Land and Rights Claims Aboriginal groups have claimed aboriginal treaty, title and rights to portions of western Canada, including British Columbia and Alberta, and such claims, if successful, could have a material negative impact on our operations or pace of growth. In 2014, the Supreme Court of Canada granted Aboriginal title over non-treaty lands, representing the first instance of such a declaration. There exist outstanding Aboriginal and treaty rights claims, which may include Aboriginal title claims, on lands where we operate. No certainty exists that any lands currently unaffected by claims brought by Aboriginal groups will remain unaffected by future claims. Recent outcomes of litigation concerning Aboriginal rights may result in increased claims and litigation activity in the future. The federal and provincial governments have a duty to consult with Aboriginal people on actions and decisions that may affect the asserted Aboriginal or treaty rights and, in certain cases, accommodate their concerns. The scope of the duty to consult by federal and provincial governments is subject to ongoing litigation. The fulfillment of the duty to consult, and where required accommodate, Aboriginal people may adversely affect our ability to, or increase the timeline to, obtain or renew, permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals. Opposition by Aboriginal groups may also negatively impact us in terms of public perception, diversion of Management’s time and resources, legal and other advisory expenses, potential blockades or other interference by third parties in our operations, or court-ordered relief impacting operations. Challenges by Aboriginal groups could adversely impact our progress and ability to explore and develop properties. In May 2016, Canada announced its support for the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). The principles and objectives of UNDRIP have also been endorsed by the Government of Alberta and the Government of British Columbia. The means of implementation of UNDRIP by government bodies are uncertain and may include an increase in consultation obligations and processes associated with project development, posing risks and creating uncertainty with respect to project regulatory approval timelines and requirements. Regulatory Risk cash flows. Regulatory risk is the risk of loss or lost opportunity resulting from the introduction of, or changes in, regulatory requirements or the failure to secure regulatory approval for upstream or downstream development projects. The implementation of new regulations or the modification of existing regulations could impact our existing and planned projects as well as result in compliance costs, adversely impacting our financial condition, results of operations and The oil and gas industry in general and our operations in particular are subject to regulation and intervention under federal, provincial, territorial, state and municipal legislation in Canada and the U.S. in matters such as, but not limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government fees; production rates; environmental protection controls; protection of certain species or lands; provincial and federal land use designations; the reduction of greenhouse gases (“GHGs”) and other emissions; the export of crude oil, natural gas and other products; the transportation of crude-by-rail or marine transport; the awarding or acquisition of exploration and production, oil sands or other interests; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possibly expropriation or cancellation of contract rights. Changes to government regulation could impact our existing and planned projects or increase capital investment or operating expenses, adversely impacting our financial condition, results of operations and cash flows. Regulatory Approvals Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that we will be able to obtain all necessary licences, permits and other approvals that may be required to carry out certain exploration and development activities on our properties. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder and Aboriginal consultation, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; habitat assessments; and other commitments or obligations. Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs. Abandonment and Reclamation Cost Risk The current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta as a general rule limits each party's liability to its proportionate ownership of an asset. In the case where one joint owner becomes insolvent and is unable to fund the A&R activities, the solvent counterparties can claim the insolvent party’s share of the remediation costs against the Orphan Well Association (the “OWA”). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including Cenovus, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites in Alberta. British Columbia has a similar liability management regime. The Alberta Court of Queen’s Bench issued a decision in the case of Redwater Energy Corporation, (“Redwater”) that trustees and receivers of insolvent parties may disclaim or renounce uneconomic oil and gas assets to the AER before commencing the sales process for the insolvent party’s assets. These wells and facilities then become “orphans” to be remediated by the OWA. The Alberta Court of Appeal upheld the trial judge's decision in Redwater (“Redwater Appeal”), and the AER has been granted leave to appeal the Redwater Appeal to the Supreme Court of Canada. In response to Redwater, the AER released Bulletin 2016-16 which, among other things, implements important changes to the AER’s procedures relating to liability management ratings, licence eligibility and licence transfers. In addition, changes with respect to licence eligibility were codified in amendments to AER Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals. Among other things, Directive 067 provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that they should not be eligible to hold AER licences. The government of British Columbia has announced similar policies. The British Columbia Oil and Gas Commission is also exploring the development of a comprehensive liability management strategy, driven in part by the Redwater decision, and the proliferation of orphan sites. The imposition of timelines for inactive sites is among the measures under consideration. These changes may impact Cenovus’s ability to transfer our licences, approvals or permits, and may result in increased costs and delays or require changes to or abandonment of projects and transactions. Because of Redwater and the current economic environment, the number of orphaned wells in Alberta has increased significantly and, accordingly, the aggregate value of the A&R liabilities assumed by the OWA has increased and may continue to increase. The OWA may seek funding for such liabilities from industry participants, including Cenovus through an increase in its annual levy, further changes to regulations or other means. While the impact on Cenovus of any legislative, regulatory or policy decisions as a result of the Redwater decision and its pending appeal cannot be reliably or accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows. Royalty Regimes Our cash flows may be directly affected by changes to royalty regimes. The governments of Alberta and British Columbia receive royalties on the production of hydrocarbons from lands in which they respectively own the mineral rights. Government regulation of Crown royalties is subject to change for a number of reasons, including, among other things, political factors. Royalties are typically calculated based on benchmark prices, productivity per well, location, date of discovery, recovery method, well depth and the nature and quality of petroleum product produced. There is also a mineral tax in each province levied on hydrocarbon production from lands in which the Crown does not own the mineral rights. The potential for changes in the royalty and mineral tax regimes applicable in the provinces in which Cenovus operates creates uncertainty relating to the ability to accurately estimate future Crown burdens and could have a significant impact on our business, financial condition, results of operations and cash flows. The Government of Alberta has implemented a modernized royalty framework (the “Modernized Framework”) which applies to all conventional wells spud on or after January 1, 2017. The Modernized Framework does not apply to oil sands production, which has its own separate royalty framework. Wells spud prior to July 13, 2016 will continue to operate under the previous royalty framework. Wells spud between such dates may elect to opt-in to the Modernized Framework if certain criteria are met. After December 31, 2026, all wells will be subject to the Modernized Framework. As part of the Modernized Framework, the Alberta government announced two new strategic royalty programs to encourage oil and gas producers to boost production and explore resources in new areas: the Enhanced Hydrocarbon Recovery Program and the Emerging Resources Program. These programs will take into account the higher costs associated with development of emerging resources and enhanced recovery methods when calculating royalty rates. The royalty structure and rates for oil sands production in Alberta remain generally unchanged following the royalty review. The Government of Alberta has indicated that it plans to modernize the process of calculating costs and collecting oil sands royalties, and has recently implemented public disclosure of cost, revenue and collection information relating to oil sands projects and royalties. 2017 ANNUAL REPORT | 49 Further changes to any of the royalty regimes in Alberta, changes to the existing royalty regimes in British Columbia, changes to how existing royalty regimes are interpreted and applied by the applicable governments, or an increase in disclosure obligations for Cenovus could have a significant impact on our business, financial condition, results of operations and cash flows. An increase in the royalty rates in Alberta or British Columbia would reduce our earnings and could make, in the respective province, future capital expenditures or existing operations uneconomic. A material increase in royalties or mineral taxes may reduce the value of our associated assets. Environmental Regulatory Risk All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a variety of Canadian and U.S. federal, provincial, territorial, state and municipal laws and regulations (collectively, the “environmental regulations”). Environmental regulations provide that wells, facility sites, refineries and other properties and practices associated with our operations be constructed, operated, maintained, abandoned, reclaimed and undertaken in accordance with the requirements set out therein. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. They also impose restrictions, liabilities and obligations in connection with the management of water sources that are being used, or whose use is contemplated, in connection with oil and gas operations. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to Cenovus. Compliance with environmental regulations can require significant expenditures, including costs and damages arising from releases or contaminated properties or spills, or from new compliance obligations. We anticipate that future capital expenditures and operating expenses could continue to increase as a result of the implementation of new environmental regulations. Failure to comply with environmental regulations may result in the imposition of fines, penalties, environmental protection orders, suspension of operations, and could adversely impact our reputation. The costs of complying with environmental regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows. The implementation of new environmental regulations or the modification of existing environmental regulations affecting the crude oil and natural gas industry generally could reduce demand for crude oil and natural gas and increase compliance costs, and have an adverse impact on our business, financial condition, results of operations and cash flows. There is also risk that we could face litigation initiated by third parties relating to climate change or other environmental regulations. Climate Change Regulation Various federal, provincial and state governments have announced intentions to regulate GHG emissions. Some of these regulations are in effect while others remain in various phases of review, discussion or implementation in the U.S. and Canada. In 2016, the Government of Canada ratified the international Paris Agreement on climate change and announced a new national carbon pricing regime (the “Carbon Strategy”). All Canadian provinces and territories except Saskatchewan and Manitoba signed the pan-Canadian framework to implement the Carbon Strategy. In 2018, the Federal Government released the draft Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which specifies (i) a carbon price on fossil fuels of $10 per tonne of carbon dioxide equivalent (“CO2e”) in 2018, rising by $10 per year to $50 per tonne CO2e in 2022 and (ii) an Output-Based Pricing System (“OBPS”) for industrial facilities with annual emissions of 50 kilotonnes of GHG per year or more. OBPS facilities will be subject to the carbon price on the portion of emissions that exceed an annual output-based emissions limit, which can be satisfied by paying a charge, applying federally issued surplus credits or eligible offset credits. The design of this system is currently under development. The Alberta Climate Leadership Plan, sets forth several commitments relevant to the oil and gas sector: (1) the implementation of an economy-wide carbon levy; (2) limiting of oil sands emissions to a province-wide total of 100 megatonnes per year (compared to current industry emissions levels of approximately 70 megatonnes per year), with certain exceptions for cogeneration power sources and new upgrading capacity; and (3) a goal to reduce methane emissions from oil and gas activities by 45 percent by 2025. The economy-wide carbon levy is based on a rate of $30 per tonne for 2018 and exempts activities integral to oil and gas production processes until 2023. The Alberta Carbon Competitiveness Incentive Regulation (“CCIR”, effective January 1, 2018) applies to facilities that emit greater than 100,000 tonnes of GHG per year. Facilities are exempt from the carbon levy, but are required to meet an emissions intensity benchmark which is set based on industry performance. Where emissions exceed the benchmark, the facility must reduce its net emissions by applying emissions offsets, emissions performance credits or fund credits against its actual emissions level. The benchmarks are subject to future adjustment. The British Columbia Carbon Tax Act sets a carbon price of $30 per tonne of CO2e on fuel combustion. Beginning April 1, 2018, the provincial carbon tax is expected to increase by $5 per tonne of CO2e per year, reaching the federal target carbon price of $50 on April 1, 2021. The tax may also be expanded to fugitive and vented emissions 50 | CENOVUS ENERGY from the oil and gas sector. The British Columbia government has signalled further measures, such as reducing upstream methane emissions by 45 percent and may establish separate sectoral reduction goals and plans. The government has also indicated their intention to work with emissions intensive industries to maintain their competitiveness. Further details have not yet been announced. In 2017, the federal government also proposed regulations to limit the release of methane and volatile organic compounds with staged implementation over the 2020 to 2023 time period. Provinces may establish their own methane reduction regulations and set up equivalency agreements with the federal government. Alberta is developing methane reduction rules that are expected to align with the federal government’s proposed regulations. It is expected that the carbon pricing systems in Alberta and British Columbia will meet the requirements of the federal Greenhouse Gas Pollution Pricing Act. Our operating oil sands assets and two of our natural gas processing facilities are subject to the CCIR and are therefore exempt from the Alberta carbon levy. The carbon levy exemption for activities integral to oil and gas production processes applies to the vast majority of emissions related to activities in our Deep Basin assets. In 2023, when the current exemptions are expected to end, we expect that some of our conventional oil and gas production facilities will be eligible to opt-in to the CCIR thereby mitigating a portion of the cost associated with the carbon levy. Uncertainties exist relating to the timing and effects of these emerging regulations, other contemplated legislation, including how they may be harmonized, making it difficult to accurately determine the cost impacts and effects on our suppliers. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time. Other possible effects from emerging regulations may also include, but are not limited to: increased compliance costs; permitting delays; substantial costs to generate or purchase emission credits or allowances, all of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be available on an economic basis, required emission reductions may not be technically or economically feasible to implement, in whole or in part, and failure to have access to such resources or technology to meet such emission reduction requirements or other compliance mechanisms may have a material adverse effect on our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations. Cenovus’s analysis suggests that we will remain financially resilient over the long-term under a range of climate policy scenarios. However, the extent and magnitude of any adverse impacts of additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance. Consequently, no assurances can be given that the effect of future climate change regulations will not be significant to Cenovus. Low Carbon Fuel Standards Existing and proposed environmental legislation developed by certain U.S. states, Canadian provinces, the Canadian federal government and members of the European Union, regulating carbon fuel standards could result in increased costs and reduced revenue. The potential regulation may negatively affect the marketing of Cenovus’s bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to affect sales in such jurisdictions. On December 13, 2017, Environment and Climate Change Canada published a regulatory framework on its proposed clean fuel standard regulation to be adopted under the Canadian Environmental Protection Act, 1999. The federal government is expected to release draft regulations in 2018. The clean fuel standard regulation will establish lifecycle carbon intensity requirements separately for liquid, gaseous and solid fuels that are used in transportation, industry and buildings. The stated purpose of the clean fuel standard is to incent the use of a broad range of low carbon fuels, energy sources and technologies. The clean fuel standard will apply to liquid, gaseous and solid fuels combusted for the purpose of creating energy, including “self-produced and used” fuels (i.e., those fuels that are used by producers or importers). The clean fuel standard regulation has the potential to impact our business, financial condition, results of operations and cash flows, though at this time it is difficult to predict or quantify any such impacts. The state of California and the province of British Columbia have implemented climate change regulation in the form of a Low Carbon Fuel Standard and the Renewable and Low Carbon Fuel Requirements Regulation, respectively. The regulations require the reduction of life cycle carbon emissions from transportation fuels. As an oil sands producer, we are not directly regulated and are not expected to have a compliance obligation. Refiners in California and British Columbia are required to comply with the legislation. Renewable Fuel Standards Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. Of specific note is the Energy Independence and Security Act of 2007 (“EISA 2007”) that established energy management goals and requirements. Pursuant to EISA 2007, among other things, the Environmental Protection Agency issued the Renewable Fuel Standard program that mandates the total volume of renewable transportation fuel sold or introduced in the U.S. and requires renewable fuels such as ethanol and advanced biofuels to be blended with gasoline by the obligated party. The mandate requires the volume of renewable fuels Further changes to any of the royalty regimes in Alberta, changes to the existing royalty regimes in British Columbia, changes to how existing royalty regimes are interpreted and applied by the applicable governments, or an increase in disclosure obligations for Cenovus could have a significant impact on our business, financial condition, results of operations and cash flows. An increase in the royalty rates in Alberta or British Columbia would reduce our earnings and could make, in the respective province, future capital expenditures or existing operations uneconomic. A material increase in royalties or mineral taxes may reduce the value of our associated assets. Environmental Regulatory Risk All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a variety of Canadian and U.S. federal, provincial, territorial, state and municipal laws and regulations (collectively, the “environmental regulations”). Environmental regulations provide that wells, facility sites, refineries and other properties and practices associated with our operations be constructed, operated, maintained, abandoned, reclaimed and undertaken in accordance with the requirements set out therein. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. They also impose restrictions, liabilities and obligations in connection with the management of water sources that are being used, or whose use is contemplated, in connection with oil and gas operations. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to Cenovus. Compliance with environmental regulations can require significant expenditures, including costs and damages arising from releases or contaminated properties or spills, or from new compliance obligations. We anticipate that future capital expenditures and operating expenses could continue to increase as a result of the implementation of new environmental regulations. Failure to comply with environmental regulations may result in the imposition of fines, penalties, environmental protection orders, suspension of operations, and could adversely impact our reputation. The costs of complying with environmental regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows. The implementation of new environmental regulations or the modification of existing environmental regulations affecting the crude oil and natural gas industry generally could reduce demand for crude oil and natural gas and increase compliance costs, and have an adverse impact on our business, financial condition, results of operations and cash flows. There is also risk that we could face litigation initiated by third parties relating to climate change or other environmental regulations. Climate Change Regulation U.S. and Canada. Various federal, provincial and state governments have announced intentions to regulate GHG emissions. Some of these regulations are in effect while others remain in various phases of review, discussion or implementation in the In 2016, the Government of Canada ratified the international Paris Agreement on climate change and announced a new national carbon pricing regime (the “Carbon Strategy”). All Canadian provinces and territories except Saskatchewan and Manitoba signed the pan-Canadian framework to implement the Carbon Strategy. In 2018, the Federal Government released the draft Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which specifies (i) a carbon price on fossil fuels of $10 per tonne of carbon dioxide equivalent (“CO2e”) in 2018, rising by $10 per year to $50 per tonne CO2e in 2022 and (ii) an Output-Based Pricing System (“OBPS”) for industrial facilities with annual emissions of 50 kilotonnes of GHG per year or more. OBPS facilities will be subject to the carbon price on the portion of emissions that exceed an annual output-based emissions limit, which can be satisfied by paying a charge, applying federally issued surplus credits or eligible offset credits. The design of this system is currently under development. The Alberta Climate Leadership Plan, sets forth several commitments relevant to the oil and gas sector: (1) the implementation of an economy-wide carbon levy; (2) limiting of oil sands emissions to a province-wide total of 100 megatonnes per year (compared to current industry emissions levels of approximately 70 megatonnes per year), with certain exceptions for cogeneration power sources and new upgrading capacity; and (3) a goal to reduce methane emissions from oil and gas activities by 45 percent by 2025. The economy-wide carbon levy is based on a rate of $30 per tonne for 2018 and exempts activities integral to oil and gas production processes until 2023. adjustment. The Alberta Carbon Competitiveness Incentive Regulation (“CCIR”, effective January 1, 2018) applies to facilities that emit greater than 100,000 tonnes of GHG per year. Facilities are exempt from the carbon levy, but are required to meet an emissions intensity benchmark which is set based on industry performance. Where emissions exceed the benchmark, the facility must reduce its net emissions by applying emissions offsets, emissions performance credits or fund credits against its actual emissions level. The benchmarks are subject to future The British Columbia Carbon Tax Act sets a carbon price of $30 per tonne of CO2e on fuel combustion. Beginning April 1, 2018, the provincial carbon tax is expected to increase by $5 per tonne of CO2e per year, reaching the federal target carbon price of $50 on April 1, 2021. The tax may also be expanded to fugitive and vented emissions from the oil and gas sector. The British Columbia government has signalled further measures, such as reducing upstream methane emissions by 45 percent and may establish separate sectoral reduction goals and plans. The government has also indicated their intention to work with emissions intensive industries to maintain their competitiveness. Further details have not yet been announced. In 2017, the federal government also proposed regulations to limit the release of methane and volatile organic compounds with staged implementation over the 2020 to 2023 time period. Provinces may establish their own methane reduction regulations and set up equivalency agreements with the federal government. Alberta is developing methane reduction rules that are expected to align with the federal government’s proposed regulations. It is expected that the carbon pricing systems in Alberta and British Columbia will meet the requirements of the federal Greenhouse Gas Pollution Pricing Act. Our operating oil sands assets and two of our natural gas processing facilities are subject to the CCIR and are therefore exempt from the Alberta carbon levy. The carbon levy exemption for activities integral to oil and gas production processes applies to the vast majority of emissions related to activities in our Deep Basin assets. In 2023, when the current exemptions are expected to end, we expect that some of our conventional oil and gas production facilities will be eligible to opt-in to the CCIR thereby mitigating a portion of the cost associated with the carbon levy. Uncertainties exist relating to the timing and effects of these emerging regulations, other contemplated legislation, including how they may be harmonized, making it difficult to accurately determine the cost impacts and effects on our suppliers. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time. Other possible effects from emerging regulations may also include, but are not limited to: increased compliance costs; permitting delays; substantial costs to generate or purchase emission credits or allowances, all of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be available on an economic basis, required emission reductions may not be technically or economically feasible to implement, in whole or in part, and failure to have access to such resources or technology to meet such emission reduction requirements or other compliance mechanisms may have a material adverse effect on our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations. Cenovus’s analysis suggests that we will remain financially resilient over the long-term under a range of climate policy scenarios. However, the extent and magnitude of any adverse impacts of additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance. Consequently, no assurances can be given that the effect of future climate change regulations will not be significant to Cenovus. Low Carbon Fuel Standards Existing and proposed environmental legislation developed by certain U.S. states, Canadian provinces, the Canadian federal government and members of the European Union, regulating carbon fuel standards could result in increased costs and reduced revenue. The potential regulation may negatively affect the marketing of Cenovus’s bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to affect sales in such jurisdictions. On December 13, 2017, Environment and Climate Change Canada published a regulatory framework on its proposed clean fuel standard regulation to be adopted under the Canadian Environmental Protection Act, 1999. The federal government is expected to release draft regulations in 2018. The clean fuel standard regulation will establish lifecycle carbon intensity requirements separately for liquid, gaseous and solid fuels that are used in transportation, industry and buildings. The stated purpose of the clean fuel standard is to incent the use of a broad range of low carbon fuels, energy sources and technologies. The clean fuel standard will apply to liquid, gaseous and solid fuels combusted for the purpose of creating energy, including “self-produced and used” fuels (i.e., those fuels that are used by producers or importers). The clean fuel standard regulation has the potential to impact our business, financial condition, results of operations and cash flows, though at this time it is difficult to predict or quantify any such impacts. The state of California and the province of British Columbia have implemented climate change regulation in the form of a Low Carbon Fuel Standard and the Renewable and Low Carbon Fuel Requirements Regulation, respectively. The regulations require the reduction of life cycle carbon emissions from transportation fuels. As an oil sands producer, we are not directly regulated and are not expected to have a compliance obligation. Refiners in California and British Columbia are required to comply with the legislation. Renewable Fuel Standards Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. Of specific note is the Energy Independence and Security Act of 2007 (“EISA 2007”) that established energy management goals and requirements. Pursuant to EISA 2007, among other things, the Environmental Protection Agency issued the Renewable Fuel Standard program that mandates the total volume of renewable transportation fuel sold or introduced in the U.S. and requires renewable fuels such as ethanol and advanced biofuels to be blended with gasoline by the obligated party. The mandate requires the volume of renewable fuels 2017 ANNUAL REPORT | 51 blended into finished petroleum products to increase over time until 2022. To the extent refineries do not blend renewable fuels into their finished products, they must purchase credits, referred to as RINs, in the open market. A RIN is a number assigned to each gallon of renewable fuel produced or imported into the U.S. RIN numbers were implemented to provide refiners with flexibility in complying with the renewable fuel standards. Our refineries do not blend renewable fuels into the motor fuel products they produce and, consequently, we are obligated, through WRB, to purchase RINs in the open market, where prices fluctuate. In the future, the regulations could change the volume of renewable fuels required to be blended with refined products, creating volatility in the price for RINs or an insufficient number of RINs being available in order to meet the requirements. Our financial condition, results of operations, and cash flows may be materially adversely impacted as a result. Marine Fuel Oil Sulphur Specification As a specialized agency of the United Nations and the main regulatory body for the shipping industry, the International Maritime Organization (“IMO”) is the global standard-setting authority for the safety, security and environmental performance of international shipping. IMO has set a global limit for sulphur in fuel oil used on board ships of 0.5 weight percent from January 1, 2020, drastically changed from the current upper limit of 3.5 weight percent. This will significantly reduce the amount of sulphur oxide emanating from ships and IMO expects major health and environmental benefits for the world, particularly for populations living close to ports and coasts. Refineries worldwide currently blend around three million barrels per day of high sulphur Residual Fuel Oil (“RFO”) with lighter oil to make bunker fuel oil for the shipping industry. RFO is an outlet at the refinery for difficult to process crude components, usually high sulphur residuum. Sulphur reduction for RFO is more difficult than for lighter distillates as the asphaltene content in RFO requires more costly and complex processing. Cenovus crude production contains a large amount of high sulphur residuum. Most of Cenovus’s crude is processed by complex refineries. However, after 2020, the availability of complex refining capacity may become scarce. This coming IMO sulphur regulation has the potential to materially adversely impact our crude marketing and may materially contribute to increased widening of the light to heavy crude oil differential, distressing pricing for heavier crude oils including bitumen. The severity of the impact depends on the enforcement of the regulation, the worldwide heavy sour crude production and additional heavy processing availability. Alberta’s Land-Use Framework Alberta’s Land-Use Framework has been implemented under the Alberta Land Stewardship Act (“ALSA”) which sets out the Government of Alberta’s approach to managing Alberta’s land and natural resources to achieve long-term economic, environmental and social goals. In some cases, ALSA amends or extinguishes previously issued consents such as regulatory permits, licences, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan. The Government of Alberta has implemented the Lower Athabasca Regional Plan (“LARP”), under the ALSA. The LARP identifies legally-binding management frameworks, including for air, land and water, which will incorporate cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation. Uncertainty exists with respect to the impact to future development applications in the areas covered by the LARP, including the potential for development restrictions and mineral rights cancellation. The Government of Alberta has also implemented the South Saskatchewan Regional Plan (“SSRP”) and has commenced the regional planning process for the North Saskatchewan Regional Plan (“NSRP”) under the ALSA. SSRP is not expected to materially impact Cenovus’s existing operations, but may impact any future development Cenovus may undertake within the region. No assurance can be given that the NSRP, or any future regional plans developed and implemented by the Government of Alberta, will not materially impact operations or future operations in their applicable regions. Species at Risk Act The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or endangered species may limit the pace and the amount of development in areas identified as critical habitat for species of concern, such as woodland caribou. Recent litigation against the federal government in relation to the Species at Risk Act has raised issues associated with the protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, the Alberta Caribou Action and Range Planning Project has been established to develop range plans and action plans with a view to achieving the maintenance and recovery of Alberta’s 15 caribou populations. Similar planning has been undertaken in British Columbia by the Ministry of Environment and the Ministry of Forests, Lands, and Natural Resource Operations. In 2017, the British Columbia government released its Draft Boreal Caribou Recovery Implementation Plan for comment, and the Alberta government released its Draft Provincial Woodland Caribou Range Plan for comment. Both draft plans focus largely on reduction of linear features, such as seismic lines. If action and range plans developed by the provinces are deemed not to provide sufficient likelihood of caribou recovery, the federal legislation includes the ability to implement measures that would preclude further development or modify existing operations. The federal and/or provincial implementation of measures to protect species at risk such as woodland caribou and their critical habitat in areas of Cenovus’s current or future operations may modify our pace and amount of development. 52 | CENOVUS ENERGY Federal Air Quality Management System The Multi-sector Air Pollutants Regulations (“MSAPR”), issued under the Canadian Environmental Protection Act, 1999, seek to protect the environment and health of Canadians by setting mandatory, nationally-consistent air pollutant emission standards. The MSAPR are aimed at equipment-specific Base-Level Industrial Emissions Requirements (“BLIERs”). Nitrogen oxide BLIERs from our non-utility boilers, heaters and reciprocating engines are regulated in accordance with specified performance standards. We do not anticipate a material impact to existing or future operations as a result of the MSAPR. Canadian Ambient Air Quality Standards (“CAAQS”) for fine particulate matter (“PM2.5”) and ozone were introduced as part of a national Air Quality Management System (“AQMS”). Provincial level implementation of the CAAQS may occur at the regional air zone level and air zone management actions may include more stringent emissions standards applicable to industrial sources from approval holders in regions where Cenovus operates that may result in adverse impacts such as but not limited to increased operating costs. Federal Review of Environmental and Regulatory Processes In 2016, the Government of Canada commenced a review of the environmental and regulatory processes administered under the National Energy Board Act, Canadian Environmental Assessment Act, Fisheries Act, and the Navigation Protection Act. In February 2018, the Government of Canada proposed amendments to the Fisheries Act and the Navigation Protection Act, and proposed the enactment of the Impact Assessment Act, and the Canadian Energy Regulator Act. The proposed Fisheries Act amendments restore the previous prohibition against “harmful alteration, disruption or destruction of fish habitat” (“HADD”) and introduce several new requirements to expand the act’s scope of protection and role of Aboriginal groups and interests. The HADD requirement may result in increased permitting requirements where our operations potentially impact fish habitat. The proposed changes to the Navigation Protection Act, including renaming the Act to the Canadian Navigable Waters Act, will expand the scope to all navigable waters, create greater oversight for navigable waters and, consistent with the Fisheries Act, introduces requirements to expand the Act’s scope of protection and the role of Aboriginal groups and interests. The proposed Impact Assessment Act, will replace the Canadian Environmental Assessment Act and, if passed, will establish the Impact Assessment Agency of Canada, which will lead and coordinate impact assessments for all designated projects, including those previously administered by the National Energy Board. The proposed amendments expand the assessment considerations beyond environment to include health, society, economy, social, gender and impacts on Aboriginal peoples. The proposed Canadian Energy Regulator Act is intended to replace the National Energy Board with the Canadian Energy Regulator and modify the regulator’s role. The proposed amendments are subject to change as they work through the Parliamentary process. The extent and magnitude of any adverse impacts of changes to the legislation or programs on project development and operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to how the legislative changes that will be implemented and what the accompanying regulations, including the designated project list, will look like. Increased environmental assessment obligations and reporting obligations may create risk of increased costs and project development delays. British Columbia Review of Environmental and Regulatory Processes In 2017, the Government of British Columbia committed to reviewing the province’s environmental assessment process and other regulatory processes, including enacting an endangered species law and harmonizing other laws related to the environment. The government has commenced a review into the adequacy and oversight of professional reliance model employed in the natural resource sector and has introduced regulations requiring spill preparedness for transporters of liquid petroleum products in British Columbia. The government has also reaffirmed their commitment to proceed with a scientific review of hydraulic fracturing to determine impacts on water and the relationship to seismic activity. The Government of British Columbia has proposed regulations relating to liquid petroleum spill response and recovery. The proposed regulations include regulating spill response times, compensation for loss of public and cultural use of land, resources or public amenities in the case of spills, and creating geographic response plans in certain areas. The government will also establish an independent scientific advisory panel to recommend whether, and how, heavy oils (such as bitumen) can be safely transported and cleaned up. As noted, while the advisory panel is proceeding, the government is proposing regulatory restrictions on the increase of diluted bitumen transportation. The extent and magnitude of any adverse impacts of changes to the legislation or policies on project development and operations cannot be estimated at this time as uncertainty exists with respect to recommendations being considered or to be developed. Increased environmental assessment obligations or transportation restrictions may create risk of increased costs and project development delays. blended into finished petroleum products to increase over time until 2022. To the extent refineries do not blend renewable fuels into their finished products, they must purchase credits, referred to as RINs, in the open market. A RIN is a number assigned to each gallon of renewable fuel produced or imported into the U.S. RIN numbers were implemented to provide refiners with flexibility in complying with the renewable fuel standards. Our refineries do not blend renewable fuels into the motor fuel products they produce and, consequently, we are obligated, through WRB, to purchase RINs in the open market, where prices fluctuate. In the future, the regulations could change the volume of renewable fuels required to be blended with refined products, creating volatility in the price for RINs or an insufficient number of RINs being available in order to meet the requirements. Our financial condition, results of operations, and cash flows may be materially adversely impacted as a result. Marine Fuel Oil Sulphur Specification As a specialized agency of the United Nations and the main regulatory body for the shipping industry, the International Maritime Organization (“IMO”) is the global standard-setting authority for the safety, security and environmental performance of international shipping. IMO has set a global limit for sulphur in fuel oil used on board ships of 0.5 weight percent from January 1, 2020, drastically changed from the current upper limit of 3.5 weight percent. This will significantly reduce the amount of sulphur oxide emanating from ships and IMO expects major health and environmental benefits for the world, particularly for populations living close to ports and coasts. Refineries worldwide currently blend around three million barrels per day of high sulphur Residual Fuel Oil (“RFO”) with lighter oil to make bunker fuel oil for the shipping industry. RFO is an outlet at the refinery for difficult to process crude components, usually high sulphur residuum. Sulphur reduction for RFO is more difficult than for lighter distillates as the asphaltene content in RFO requires more costly and complex processing. Cenovus crude production contains a large amount of high sulphur residuum. Most of Cenovus’s crude is processed by complex refineries. However, after 2020, the availability of complex refining capacity may become scarce. This coming IMO sulphur regulation has the potential to materially adversely impact our crude marketing and may materially contribute to increased widening of the light to heavy crude oil differential, distressing pricing for heavier crude oils including bitumen. The severity of the impact depends on the enforcement of the regulation, the worldwide heavy sour crude production and additional heavy processing availability. Alberta’s Land-Use Framework Alberta’s Land-Use Framework has been implemented under the Alberta Land Stewardship Act (“ALSA”) which sets out the Government of Alberta’s approach to managing Alberta’s land and natural resources to achieve long-term economic, environmental and social goals. In some cases, ALSA amends or extinguishes previously issued consents such as regulatory permits, licences, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan. The Government of Alberta has implemented the Lower Athabasca Regional Plan (“LARP”), under the ALSA. The LARP identifies legally-binding management frameworks, including for air, land and water, which will incorporate cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation. Uncertainty exists with respect to the impact to future development applications in the areas covered by the LARP, including the potential for development restrictions and mineral rights cancellation. The Government of Alberta has also implemented the South Saskatchewan Regional Plan (“SSRP”) and has commenced the regional planning process for the North Saskatchewan Regional Plan (“NSRP”) under the ALSA. SSRP is not expected to materially impact Cenovus’s existing operations, but may impact any future development Cenovus may undertake within the region. No assurance can be given that the NSRP, or any future regional plans developed and implemented by the Government of Alberta, will not materially impact operations or future operations in their applicable regions. Species at Risk Act The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or endangered species may limit the pace and the amount of development in areas identified as critical habitat for species of concern, such as woodland caribou. Recent litigation against the federal government in relation to the Species at Risk Act has raised issues associated with the protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, the Alberta Caribou Action and Range Planning Project has been established to develop range plans and action plans with a view to achieving the maintenance and recovery of Alberta’s 15 caribou populations. Similar planning has been undertaken in British Columbia by the Ministry of Environment and the Ministry of Forests, Lands, and Natural Resource Operations. In 2017, the British Columbia government released its Draft Boreal Caribou Recovery Implementation Plan for comment, and the Alberta government released its Draft Provincial Woodland Caribou Range Plan for comment. Both draft plans focus largely on reduction of linear features, such as seismic lines. If action and range plans developed by the provinces are deemed not to provide sufficient likelihood of caribou recovery, the federal legislation includes the ability to implement measures that would preclude further development or modify existing operations. The federal and/or provincial implementation of measures to protect species at risk such as woodland caribou and their critical habitat in areas of Cenovus’s current or future operations may modify our pace and amount of development. Federal Air Quality Management System The Multi-sector Air Pollutants Regulations (“MSAPR”), issued under the Canadian Environmental Protection Act, 1999, seek to protect the environment and health of Canadians by setting mandatory, nationally-consistent air pollutant emission standards. The MSAPR are aimed at equipment-specific Base-Level Industrial Emissions Requirements (“BLIERs”). Nitrogen oxide BLIERs from our non-utility boilers, heaters and reciprocating engines are regulated in accordance with specified performance standards. We do not anticipate a material impact to existing or future operations as a result of the MSAPR. Canadian Ambient Air Quality Standards (“CAAQS”) for fine particulate matter (“PM2.5”) and ozone were introduced as part of a national Air Quality Management System (“AQMS”). Provincial level implementation of the CAAQS may occur at the regional air zone level and air zone management actions may include more stringent emissions standards applicable to industrial sources from approval holders in regions where Cenovus operates that may result in adverse impacts such as but not limited to increased operating costs. Federal Review of Environmental and Regulatory Processes In 2016, the Government of Canada commenced a review of the environmental and regulatory processes administered under the National Energy Board Act, Canadian Environmental Assessment Act, Fisheries Act, and the Navigation Protection Act. In February 2018, the Government of Canada proposed amendments to the Fisheries Act and the Navigation Protection Act, and proposed the enactment of the Impact Assessment Act, and the Canadian Energy Regulator Act. The proposed Fisheries Act amendments restore the previous prohibition against “harmful alteration, disruption or destruction of fish habitat” (“HADD”) and introduce several new requirements to expand the act’s scope of protection and role of Aboriginal groups and interests. The HADD requirement may result in increased permitting requirements where our operations potentially impact fish habitat. The proposed changes to the Navigation Protection Act, including renaming the Act to the Canadian Navigable Waters Act, will expand the scope to all navigable waters, create greater oversight for navigable waters and, consistent with the Fisheries Act, introduces requirements to expand the Act’s scope of protection and the role of Aboriginal groups and interests. The proposed Impact Assessment Act, will replace the Canadian Environmental Assessment Act and, if passed, will establish the Impact Assessment Agency of Canada, which will lead and coordinate impact assessments for all designated projects, including those previously administered by the National Energy Board. The proposed amendments expand the assessment considerations beyond environment to include health, society, economy, social, gender and impacts on Aboriginal peoples. The proposed Canadian Energy Regulator Act is intended to replace the National Energy Board with the Canadian Energy Regulator and modify the regulator’s role. The proposed amendments are subject to change as they work through the Parliamentary process. The extent and magnitude of any adverse impacts of changes to the legislation or programs on project development and operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to how the legislative changes that will be implemented and what the accompanying regulations, including the designated project list, will look like. Increased environmental assessment obligations and reporting obligations may create risk of increased costs and project development delays. British Columbia Review of Environmental and Regulatory Processes In 2017, the Government of British Columbia committed to reviewing the province’s environmental assessment process and other regulatory processes, including enacting an endangered species law and harmonizing other laws related to the environment. The government has commenced a review into the adequacy and oversight of professional reliance model employed in the natural resource sector and has introduced regulations requiring spill preparedness for transporters of liquid petroleum products in British Columbia. The government has also reaffirmed their commitment to proceed with a scientific review of hydraulic fracturing to determine impacts on water and the relationship to seismic activity. The Government of British Columbia has proposed regulations relating to liquid petroleum spill response and recovery. The proposed regulations include regulating spill response times, compensation for loss of public and cultural use of land, resources or public amenities in the case of spills, and creating geographic response plans in certain areas. The government will also establish an independent scientific advisory panel to recommend whether, and how, heavy oils (such as bitumen) can be safely transported and cleaned up. As noted, while the advisory panel is proceeding, the government is proposing regulatory restrictions on the increase of diluted bitumen transportation. The extent and magnitude of any adverse impacts of changes to the legislation or policies on project development and operations cannot be estimated at this time as uncertainty exists with respect to recommendations being considered or to be developed. Increased environmental assessment obligations or transportation restrictions may create risk of increased costs and project development delays. 2017 ANNUAL REPORT | 53 Water Licences In Alberta, we utilize fresh water in certain operations, which is obtained under licences issued pursuant to the Water Act to provide domestic and utility water at our SAGD facilities and for our bitumen delineation programs and our activities in the Deep Basin. Currently, we are not required to pay for the water we use under these licenses. There can be no assurance that we will not have to pay a fee for the use of water in the future or that any such fees will be reasonable. If a change under these licences reduces the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial performance. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. In addition, the expansion of our projects rely on securing licences for additional water withdrawal, and there can be no assurance that these licences will be granted on terms favourable to us, or at all, or that such additional water will in fact be available to divert under such licences. In British Columbia, groundwater use is regulated with the coming into force of the Water Sustainability Act. Most groundwater use (other than domestic use) requires a water licence to divert water from an aquifer. There is a three year period for existing non-domestic groundwater users to transition into the current water licensing scheme and its first-in-time, first-in-right priority system. There are annual water rental fees established by the regulations to the Water Sustainability Act. Additional supporting regulations continue to be proposed and brought into force. Water use fees may increase and licence terms and conditions may be amended in the future, which may adversely affect our business including ability to operate. In addition, there is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted on favourable terms. Alberta Wetland Policy Wetland management within Alberta is regulated by section 36 of the Water Act, together with the Alberta Wetland Policy and the Provincial Wetland Restoration and Compensation Guide. Pursuant to the Alberta Wetland Policy, developers of oil and gas assets in wetlands areas may be required to avoid the wetlands or mitigate the development’s effects on wetlands. The Alberta Wetland Policy is not expected to affect Cenovus’s existing operations in Foster Creek, Christina Lake and Narrows Lake, where our 10 year wetlands mitigation and monitoring plans were approved under the previous wetland policy. However, new project developments and future phase expansions will likely be affected by aspects of this policy as our oil sands leases are in areas where wetlands cover over 50 percent of the landscape. Development of some projects within our Deep Basin asset near wetland regions will also be affected by the policy. ‘Avoidance’ may not be an option for new projects, developments and phase expansions. We expect to be required to comply with requirements for wetland reclamation or, where permanent wetland loss will occur, wetland replacement. In accordance with the Alberta Wetland Restoration Directive, 2016, mechanisms for restorative replacement include purchase of credits (under development), payment to an in-lieu fee program, or permittee-responsible replacement action. Based on written statements in the Alberta Wetland Mitigation Directive, 2016 and consultation with Alberta Environment and Parks as well as the AER, we do not anticipate a material impact on our oil sands or unconventional assets in the Deep Basin. However, it remains unclear how the policy will be implemented and no assurance can be given that the policy will not have an impact on future development plans at this time. Hydraulic Fracturing Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and suggest that additional federal, provincial, territorial and/or municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process. The Canadian federal government and certain provincial governments continue to review certain aspects of the existing scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. Further, certain governments in jurisdictions where the Company does not currently operate have considered or implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments have adopted, and others have considered adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to limitations or restrictions to oil and gas development activities, operational delays, additional operating requirements, or increased third-party or governmental claims that could increase our cost of compliance and doing business as well as reduce the amount of natural gas and oil that Cenovus is ultimately able to produce from its reserves. Seismic Activity Some areas of British Columbia and Alberta are experiencing increasing localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been correlated with hydraulic fracturing in western Canada which has prompted legislative and regulatory initiatives intended to address these concerns. 54 | CENOVUS ENERGY These initiatives have the potential to require additional monitoring, restrict the injection of produced water in certain disposal wells and/or modify or curtail hydraulic fracturing operations which could lead to operational delays, increase compliance costs or otherwise adversely impact Cenovus’s operations. Oil and Gas Activities Act In British Columbia, the Oil and Gas Activities Act (the “OGAA”) impacts conventional crude oil and natural gas producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the “Commission”) has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for oil and natural gas activities. The Environmental Protection and Management Regulation establishes the government’s environmental objectives for Crown lands, water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, although not exclusively an environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires companies to obtain various approvals before undertaking exploration or production work, such as geophysical licenses, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licenses and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations. Reputation Risk continue operations. Public Perception of Alberta Oil Sands We rely on our reputation to build and maintain positive relationships with stakeholders, to recruit and retain staff, and to be a credible, trusted company. Any actions we take that cause negative public opinion have the potential to negatively impact our reputation which may adversely affect our share price, development plans and our ability to Development of the Alberta oil sands has received considerable attention in recent public commentary on the subjects of environmental impact, climate change and GHG emissions. Despite that much of the focus is on bitumen mining operations and not in-situ production, public concerns about oil sands generally and GHG emissions and water and land use practices in oil sands developments specifically may, directly or indirectly, impair the profitability of our current oil sands projects, and the viability of future oil sands projects, by creating significant regulatory uncertainty leading to uncertainty in economic modeling of current and future projects and delays relating to the sanctioning of future projects. Negative consequences which could arise as a result of changes to the current regulatory environment include, but are not limited to, extraordinary environmental and emissions regulation of current and future projects by governmental authorities, which could result in changes to facility design and operating requirements, thereby potentially increasing the cost of construction, operation and abandonment. In addition, legislation or policies that limit the purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or foreign jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in stranded assets or an inability to further develop oil resources. Other Risks Risks Related to the Acquisition Unexpected Costs or Liabilities Related to the Acquisition Acquisitions of crude oil and natural gas properties are based largely on engineering, environmental and economic assessments made by the acquirer, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of crude oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of crude oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated. Although we conducted title and environmental reviews in respect of the Deep Basin assets, which include approximately three million net acres of land containing liquids rich natural gas, condensate and other NGLs, and light and medium oil located primarily in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas and include interests in numerous natural gas processing facilities, such reviews cannot guarantee that any unforeseen defects in the chain of title will not arise to defeat our title to certain assets or that environmental defects or deficiencies do not exist. In connection with the Acquisition, there may be liabilities that we failed to discover or were unable to quantify in our due diligence conducted prior to the execution of the purchase and sale agreement between ConocoPhillips and Cenovus dated March 29, 2017, as amended (the “Acquisition Agreement”), and we may not be indemnified for Water Licences In Alberta, we utilize fresh water in certain operations, which is obtained under licences issued pursuant to the Water Act to provide domestic and utility water at our SAGD facilities and for our bitumen delineation programs and our activities in the Deep Basin. Currently, we are not required to pay for the water we use under these licenses. There can be no assurance that we will not have to pay a fee for the use of water in the future or that any such fees will be reasonable. If a change under these licences reduces the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial performance. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. In addition, the expansion of our projects rely on securing licences for additional water withdrawal, and there can be no assurance that these licences will be granted on terms favourable to us, or at all, or that such additional water will in fact be available to divert under such licences. In British Columbia, groundwater use is regulated with the coming into force of the Water Sustainability Act. Most groundwater use (other than domestic use) requires a water licence to divert water from an aquifer. There is a three year period for existing non-domestic groundwater users to transition into the current water licensing scheme and its first-in-time, first-in-right priority system. There are annual water rental fees established by the regulations to the Water Sustainability Act. Additional supporting regulations continue to be proposed and brought into force. Water use fees may increase and licence terms and conditions may be amended in the future, which may adversely affect our business including ability to operate. In addition, there is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted on favourable terms. Alberta Wetland Policy Wetland management within Alberta is regulated by section 36 of the Water Act, together with the Alberta Wetland Policy and the Provincial Wetland Restoration and Compensation Guide. the wetlands or mitigate the development’s effects on wetlands. The Alberta Wetland Policy is not expected to affect Cenovus’s existing operations in Foster Creek, Christina Lake and Narrows Lake, where our 10 year wetlands mitigation and monitoring plans were approved under the previous wetland policy. However, new project developments and future phase expansions will likely be affected by aspects of this policy as our oil sands leases are in areas where wetlands cover over 50 percent of the landscape. Development of some projects within our Deep Basin asset near wetland regions will also be affected by the policy. ‘Avoidance’ may not be an option for new projects, developments and phase expansions. We expect to be required to comply with requirements for wetland reclamation or, where permanent wetland loss will occur, wetland replacement. In accordance with the Alberta Wetland Restoration Directive, 2016, mechanisms for restorative replacement include purchase of credits (under development), payment to an in-lieu fee program, or permittee-responsible replacement action. Based on written statements in the Alberta Wetland Mitigation Directive, 2016 and consultation with Alberta Environment and Parks as well as the AER, we do not anticipate a material impact on our oil sands or unconventional assets in the Deep Basin. However, it remains unclear how the policy will be implemented and no assurance can be given that the policy will not have an impact on future development plans at this time. Hydraulic Fracturing Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and suggest that additional federal, provincial, territorial and/or municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process. The Canadian federal government and certain provincial governments continue to review certain aspects of the existing scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. Further, certain governments in jurisdictions where the Company does not currently operate have considered or implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments have adopted, and others have considered adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to limitations or restrictions to oil and gas development activities, operational delays, additional operating requirements, or increased third-party or governmental claims that could increase our cost of compliance and doing business as well as reduce the amount of natural gas and oil that Cenovus is ultimately able to produce from its reserves. Seismic Activity Some areas of British Columbia and Alberta are experiencing increasing localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been correlated with hydraulic fracturing in western Canada which has prompted legislative and regulatory initiatives intended to address these concerns. These initiatives have the potential to require additional monitoring, restrict the injection of produced water in certain disposal wells and/or modify or curtail hydraulic fracturing operations which could lead to operational delays, increase compliance costs or otherwise adversely impact Cenovus’s operations. Oil and Gas Activities Act In British Columbia, the Oil and Gas Activities Act (the “OGAA”) impacts conventional crude oil and natural gas producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the “Commission”) has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for oil and natural gas activities. The Environmental Protection and Management Regulation establishes the government’s environmental objectives for Crown lands, water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, although not exclusively an environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires companies to obtain various approvals before undertaking exploration or production work, such as geophysical licenses, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licenses and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations. Reputation Risk We rely on our reputation to build and maintain positive relationships with stakeholders, to recruit and retain staff, and to be a credible, trusted company. Any actions we take that cause negative public opinion have the potential to negatively impact our reputation which may adversely affect our share price, development plans and our ability to continue operations. Pursuant to the Alberta Wetland Policy, developers of oil and gas assets in wetlands areas may be required to avoid Public Perception of Alberta Oil Sands Development of the Alberta oil sands has received considerable attention in recent public commentary on the subjects of environmental impact, climate change and GHG emissions. Despite that much of the focus is on bitumen mining operations and not in-situ production, public concerns about oil sands generally and GHG emissions and water and land use practices in oil sands developments specifically may, directly or indirectly, impair the profitability of our current oil sands projects, and the viability of future oil sands projects, by creating significant regulatory uncertainty leading to uncertainty in economic modeling of current and future projects and delays relating to the sanctioning of future projects. Negative consequences which could arise as a result of changes to the current regulatory environment include, but are not limited to, extraordinary environmental and emissions regulation of current and future projects by governmental authorities, which could result in changes to facility design and operating requirements, thereby potentially increasing the cost of construction, operation and abandonment. In addition, legislation or policies that limit the purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or foreign jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in stranded assets or an inability to further develop oil resources. Other Risks Risks Related to the Acquisition Unexpected Costs or Liabilities Related to the Acquisition Acquisitions of crude oil and natural gas properties are based largely on engineering, environmental and economic assessments made by the acquirer, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of crude oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of crude oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated. Although we conducted title and environmental reviews in respect of the Deep Basin assets, which include approximately three million net acres of land containing liquids rich natural gas, condensate and other NGLs, and light and medium oil located primarily in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas and include interests in numerous natural gas processing facilities, such reviews cannot guarantee that any unforeseen defects in the chain of title will not arise to defeat our title to certain assets or that environmental defects or deficiencies do not exist. In connection with the Acquisition, there may be liabilities that we failed to discover or were unable to quantify in our due diligence conducted prior to the execution of the purchase and sale agreement between ConocoPhillips and Cenovus dated March 29, 2017, as amended (the “Acquisition Agreement”), and we may not be indemnified for 2017 ANNUAL REPORT | 55 some or all of these liabilities. The discovery or quantification of any material liabilities could have a material adverse effect on our business, financial condition or future prospects. In addition, the Acquisition Agreement limits the amount for which we are indemnified, such that liabilities in respect of the Acquisition may be greater than the amounts for which we are indemnified under the Acquisition Agreement. Realization of Acquisition Benefits We believe that the Acquisition will provide a number of benefits to Cenovus. However, there is a risk that some or all of the expected benefits of the Acquisition may fail to materialize, may cost more to achieve or may not occur within the time periods that we anticipate. The realization of such benefits may be affected by a number of factors, many of which are beyond our control. Amount of Contingent Payments In connection with the Acquisition, we have agreed to make contingent payments under certain circumstances. The amount of contingent payments will vary depending on the Canadian dollar WCS price from time to time during the five year period following the closing of the Acquisition, and such payments may be significant. In addition, in the event that such payments are made, this could have an adverse impact on our reported results and other metrics. Effect on Market Price from Future Sales of common shares of Cenovus by ConocoPhillips The future sales of common shares of Cenovus into the market held by ConocoPhillips, either through open market trades on the TSX or NYSE, through privately arranged block trades, or pursuant to prospectus offerings made in accordance with the registration rights agreement, could adversely affect prevailing market prices for the common shares. In addition, market perception regarding ConocoPhillips' intention to make sales of Cenovus common shares may have a negative impact on the trading price of these common shares. Tax Laws Income tax laws, other laws or government incentive programs may in the future be changed or interpreted in a manner that adversely affects Cenovus and its shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s detriment or the detriment of its shareholders. In addition, all of our tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders. United States Tax Risk In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The new legislation: reduces the federal corporate tax rate from 35 percent to 21 percent; allows immediate expensing of qualified property acquired prior to 2023; imposes a limitation on the utilization of net operating losses to 80 percent of taxable income; sets a limitation on the deductibility of interest expense; and introduces new provisions imposing a minimum tax in certain circumstances when a company has payments to a related foreign entity. There are currently significant gaps in the legislation that will reportedly be supplemented with regulations. Accordingly, there is significant uncertainty with respect to the interpretation and implementation of the legislation. There is also potential for some or all of the changes to be revised or reversed if there is a change in governing party. We expect there will be impacts to Cenovus in terms of the U.S. taxes paid by us, but it is difficult to estimate the potential magnitude and timing of impacts to Cenovus due to the uncertainties noted with respect to the Tax Cuts and Jobs Act. United States Trade Risk relating to NAFTA Renegotiation The outcome of the ongoing renegotiation of the North American Free Trade Agreement (“NAFTA”) could include significant changes to, or U.S. withdrawal from, the treaty. While Cenovus is not aware of any proposals in the renegotiation to materially alter the terms of trade for energy resources, if the outcome of the renegotiation did include any such changes, or if the U.S. were to withdraw from the NAFTA and adopt discriminatory or other measures adversely affecting the sale or transportation of our products in the U.S., this could have a significant negative impact on our financial condition or results from operations. Arrangement Related Risk We have certain post-Arrangement indemnification and other obligations under each of the arrangement agreement (the “Arrangement Agreement”) and the separation and transition agreement (the “Separation Agreement”), both of which are among Encana Corporation (“Encana”), 7050372 Canada Inc. and Cenovus Energy Inc. (formerly, Encana Finance Ltd.), dated October 20, 2009 and November 30, 2009 respectively, entered in connection with the Arrangement. Encana and Cenovus have agreed to indemnify each other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity, the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the Cenovus business and assets. At the present time, we cannot determine whether we will have to indemnify Encana for any substantial obligations under the terms of the Arrangement. We also cannot assure that if Encana has to indemnify us and our affiliates for any substantial obligations, Encana will be able to satisfy such obligations. 56 | CENOVUS ENERGY A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business, prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com. CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES Management is required to make estimates and assumptions, and use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements. Critical Judgments in Applying Accounting Policies Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our Consolidated Financial Statements. Joint Arrangements The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10, and, accordingly, FCCL has been consolidated. In determining the classification of its joint arrangements under IFRS 11, we considered the following: The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life. The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings. FCCL operates like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business. Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles. In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements. • • • • • Exploration and Evaluation Assets The application of Cenovus’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and Cenovus’s internal approval process. Identification of CGUs CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its some or all of these liabilities. The discovery or quantification of any material liabilities could have a material adverse effect on our business, financial condition or future prospects. In addition, the Acquisition Agreement limits the amount for which we are indemnified, such that liabilities in respect of the Acquisition may be greater than the amounts for which we are indemnified under the Acquisition Agreement. Realization of Acquisition Benefits We believe that the Acquisition will provide a number of benefits to Cenovus. However, there is a risk that some or all of the expected benefits of the Acquisition may fail to materialize, may cost more to achieve or may not occur within the time periods that we anticipate. The realization of such benefits may be affected by a number of factors, many of which are beyond our control. Amount of Contingent Payments In connection with the Acquisition, we have agreed to make contingent payments under certain circumstances. The amount of contingent payments will vary depending on the Canadian dollar WCS price from time to time during the five year period following the closing of the Acquisition, and such payments may be significant. In addition, in the event that such payments are made, this could have an adverse impact on our reported results and other metrics. Effect on Market Price from Future Sales of common shares of Cenovus by ConocoPhillips The future sales of common shares of Cenovus into the market held by ConocoPhillips, either through open market trades on the TSX or NYSE, through privately arranged block trades, or pursuant to prospectus offerings made in accordance with the registration rights agreement, could adversely affect prevailing market prices for the common shares. In addition, market perception regarding ConocoPhillips' intention to make sales of Cenovus common shares may have a negative impact on the trading price of these common shares. Tax Laws Income tax laws, other laws or government incentive programs may in the future be changed or interpreted in a manner that adversely affects Cenovus and its shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s detriment or the detriment of its shareholders. In addition, all of our tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders. United States Tax Risk In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The new legislation: reduces the federal corporate tax rate from 35 percent to 21 percent; allows immediate expensing of qualified property acquired prior to 2023; imposes a limitation on the utilization of net operating losses to 80 percent of taxable income; sets a limitation on the deductibility of interest expense; and introduces new provisions imposing a minimum tax in certain circumstances when a company has payments to a related foreign entity. There are currently significant gaps in the legislation that will reportedly be supplemented with regulations. Accordingly, there is significant uncertainty with respect to the interpretation and implementation of the legislation. There is also potential for some or all of the changes to be revised or reversed if there is a change in governing party. We expect there will be impacts to Cenovus in terms of the U.S. taxes paid by us, but it is difficult to estimate the potential magnitude and timing of impacts to Cenovus due to the uncertainties noted with respect to the Tax Cuts and Jobs Act. United States Trade Risk relating to NAFTA Renegotiation The outcome of the ongoing renegotiation of the North American Free Trade Agreement (“NAFTA”) could include significant changes to, or U.S. withdrawal from, the treaty. While Cenovus is not aware of any proposals in the renegotiation to materially alter the terms of trade for energy resources, if the outcome of the renegotiation did include any such changes, or if the U.S. were to withdraw from the NAFTA and adopt discriminatory or other measures adversely affecting the sale or transportation of our products in the U.S., this could have a significant negative impact on our financial condition or results from operations. Arrangement Related Risk We have certain post-Arrangement indemnification and other obligations under each of the arrangement agreement (the “Arrangement Agreement”) and the separation and transition agreement (the “Separation Agreement”), both of which are among Encana Corporation (“Encana”), 7050372 Canada Inc. and Cenovus Energy Inc. (formerly, Encana Finance Ltd.), dated October 20, 2009 and November 30, 2009 respectively, entered in connection with the Arrangement. Encana and Cenovus have agreed to indemnify each other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity, the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the Cenovus business and assets. At the present time, we cannot determine whether we will have to indemnify Encana for any substantial obligations under the terms of the Arrangement. We also cannot assure that if Encana has to indemnify us and our affiliates for any substantial obligations, Encana will be able to satisfy such obligations. A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business, prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com. CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES Management is required to make estimates and assumptions, and use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements. Critical Judgments in Applying Accounting Policies Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our Consolidated Financial Statements. Joint Arrangements The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10, and, accordingly, FCCL has been consolidated. In determining the classification of its joint arrangements under IFRS 11, we considered the following: • The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life. • • • • The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings. FCCL operates like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business. Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles. In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements. Exploration and Evaluation Assets The application of Cenovus’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and Cenovus’s internal approval process. Identification of CGUs CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its 2017 ANNUAL REPORT | 57 operations. The recoverability of Cenovus’s upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals. Key Sources of Estimation Uncertainty Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. Crude Oil and Natural Gas Reserves There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test and DD&A expense of our crude oil and natural gas assets in the Oil Sands and Deep Basin segments. Cenovus’s crude oil and natural gas reserves are evaluated annually and reported to Cenovus by our IQREs. Refer to the Outlook section of this MD&A for more details on future commodity prices. Recoverable Amounts Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For our upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions, and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets. Refer to the Reportable Segments section of this MD&A for more details on impairments and reversals. As at December 31, 2017, the recoverable amounts of Cenovus’s upstream CGUs were determined based on fair value less costs of disposal or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs. Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2017 by our IQREs. Crude Oil and Natural Gas Prices The forward prices as at December 31, 2017, used to determine future cash flows from crude oil and natural gas reserves were: WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) 2018 57.50 50.61 72.41 2.43 2019 60.90 56.59 74.90 2.77 2020 64.13 60.86 77.07 3.19 2021 68.33 64.56 81.07 3.48 (1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet. Discount and Inflation Rates Average Annual Increase Thereafter 2.1% 2.1% 2.1% 2.0% 2022 71.19 66.63 83.32 3.67 Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent, based on the individual characteristics of the CGU and other economic and operating factors. Inflation is estimated at two percent, which is common industry practice and used by Cenovus’s IQREs in preparing their reserves reports. Decommissioning Costs Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to 58 | CENOVUS ENERGY settle the obligation and may change in response to numerous market factors. Refer to Note 24 of the Consolidated Financial Statements for more details on changes to decommissioning costs. Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward prices, reserve and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets. Income Tax Provisions Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. Refer to the Corporate and Eliminations section of this MD&A for more details on changes to estimates related to income taxes. Recent Accounting Pronouncements There were no new or amended accounting standards or interpretations adopted during 2017. New Accounting Standards and Interpretations not yet Adopted A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates: Financial Instruments On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, we have elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in other comprehensive income (“OCI”), impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition. IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities. adoption. not be restated. A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Based on Management’s assessment, no additional impairment loss is expected as at January 1, 2018, the date of In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting. IFRS 9 must be adopted for years beginning on or after January 1, 2018. We will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will operations. The recoverability of Cenovus’s upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and settle the obligation and may change in response to numerous market factors. Refer to Note 24 of the Consolidated Financial Statements for more details on changes to decommissioning costs. reversals. Key Sources of Estimation Uncertainty Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. Crude Oil and Natural Gas Reserves There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test and DD&A expense of our crude oil and natural gas assets in the Oil Sands and Deep Basin segments. Cenovus’s crude oil and natural gas reserves are evaluated annually and reported to Cenovus by our IQREs. Refer to the Outlook section of this MD&A for more details on future commodity prices. Recoverable Amounts Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For our upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions, and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets. Refer to the Reportable Segments section of this MD&A for more details on impairments and reversals. As at December 31, 2017, the recoverable amounts of Cenovus’s upstream CGUs were determined based on fair value less costs of disposal or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs. Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2017 by our IQREs. Crude Oil and Natural Gas Prices reserves were: The forward prices as at December 31, 2017, used to determine future cash flows from crude oil and natural gas 2018 57.50 50.61 72.41 2.43 2019 60.90 56.59 74.90 2.77 2020 64.13 60.86 77.07 3.19 2021 68.33 64.56 81.07 3.48 Average Annual Increase 2022 Thereafter 71.19 66.63 83.32 3.67 2.1% 2.1% 2.1% 2.0% WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) Discount and Inflation Rates reports. Decommissioning Costs (1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet. Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent, based on the individual characteristics of the CGU and other economic and operating factors. Inflation is estimated at two percent, which is common industry practice and used by Cenovus’s IQREs in preparing their reserves Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward prices, reserve and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets. Income Tax Provisions Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. Refer to the Corporate and Eliminations section of this MD&A for more details on changes to estimates related to income taxes. Recent Accounting Pronouncements There were no new or amended accounting standards or interpretations adopted during 2017. New Accounting Standards and Interpretations not yet Adopted A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates: Financial Instruments On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, we have elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in other comprehensive income (“OCI”), impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition. IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities. A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Based on Management’s assessment, no additional impairment loss is expected as at January 1, 2018, the date of adoption. In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting. IFRS 9 must be adopted for years beginning on or after January 1, 2018. We will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will not be restated. 2017 ANNUAL REPORT | 59 Revenue Recognition Summary financial information related to the Deep Basin Assets included in the Consolidated Financial Statements On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded. Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice. The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. We intend to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. We will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption. Leases On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than twelve months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded. IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on our Consolidated Balance Sheets due to material operating lease commitments as disclosed in Note 36 of the Consolidated Financial Statements. Cenovus will adopt IFRS 16 effective January 1, 2019. We intend to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available. Uncertain Tax Positions In June 2017, the IASB issued International Financial Reporting Interpretation Committee (“IFRIC”) 23, “Uncertainty over Income Tax Treatments”. The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements. CONTROL ENVIRONMENT Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at December 31, 2017. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2017. Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at December 31, 2017 because they were acquired by the Company through a business combination in 2017. As permitted by and in accordance with, National Instrument 52-109, “Certification of Disclosure in Issuers’ Annual and Interim Filings”, and guidance issued by the U.S. Securities and Exchange Commission, Management has limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin Assets. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P relating to the Deep Basin Assets in a manner consistent with our other operations. 60 | CENOVUS ENERGY is as follows: ($ millions) Revenues Operating Margin Net Earnings (Loss) As at Current Assets Non-Current Assets Current Liabilities Non-Current Liabilities May 17 - December 31, 2017 December 31, 2017 514 207 (108) 619 6,075 364 496 In addition, we acquired Deep Basin commitments of approximately $500 million, primarily consisting of transportation commitments on various pipelines. The effectiveness of our ICFR, which excludes the Deep Basin assets, was audited as at December 31, 2017 by PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2017. Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. CORPORATE RESPONSIBILITY We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the way we conduct our business. Our Corporate Responsibility (“CR”) policy guides our activities in the areas of: Leadership, Corporate Governance and Business Practices, People, Environmental Performance, Stakeholder and Aboriginal Engagement, and Community Involvement and Investment. We published our 2016 CR report in July 2017 to report on our management efforts and performance across the above noted areas within our CR policy, as well as other environment, social and governance topics that are important to our stakeholders. Our CR report also lists external recognition we received for our commitment to corporate responsibility, and is available on our website at cenovus.com. OUTLOOK We will continue to look for ways to increase our margins through strong operating performance and cost leadership, while delivering safe and reliable operations. Proactively managing our market access commitments and opportunities should assist with our goal of reaching a broader customer base to secure a higher sales price for our liquids production. We have reduced the amount of capital needed to sustain our base business and expand our projects, which we believe will help to ensure our financial resilience. The following outlook commentary is focused on the next twelve months. Commodity Prices Underlying our Financial Results Our crude oil pricing outlook is influenced by the following: • We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current price environment, the impact of potential supply disruptions, and the pace of growth in global demand as influenced by macro-economic events. Overall, we expect crude oil price volatility to continue and a modest price improvement in the next twelve months. OPEC’s ability to adhere to its current production cuts and the possibility of future production cuts, combined with annual increases in demand growth should support prices, constrained by the need to draw down surplus crude oil inventories and U.S. production growth; • We anticipate the Brent-WTI differential will narrow after the impacts of severe weather related incidents dissipate and as a result of the U.S. exporting crude oil to overseas markets. Overall, the differential will likely • We expect that the WTI-WCS differential will widen due to Canadian supply increasing due to the resolution of production outages, oil sands supply growth and transportation constraints, partially offset by the possibility of be set by transportation costs; and OPEC extending production cuts. Revenue Recognition On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded. Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice. The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. We intend to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. We will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption. Leases On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than twelve months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded. IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on our Consolidated Balance Sheets due to material operating lease commitments as disclosed in Note 36 of the Consolidated Financial Statements. Cenovus will adopt IFRS 16 effective January 1, 2019. We intend to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available. Uncertain Tax Positions In June 2017, the IASB issued International Financial Reporting Interpretation Committee (“IFRIC”) 23, “Uncertainty over Income Tax Treatments”. The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements. CONTROL ENVIRONMENT Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at December 31, 2017. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2017. Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at December 31, 2017 because they were acquired by the Company through a business combination in 2017. As permitted by and in accordance with, National Instrument 52-109, “Certification of Disclosure in Issuers’ Annual and Interim Filings”, and guidance issued by the U.S. Securities and Exchange Commission, Management has limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin Assets. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P relating to the Deep Basin Assets in a manner consistent with our other operations. Summary financial information related to the Deep Basin Assets included in the Consolidated Financial Statements is as follows: ($ millions) Revenues Operating Margin Net Earnings (Loss) As at Current Assets Non-Current Assets Current Liabilities Non-Current Liabilities May 17 - December 31, 2017 514 207 (108) December 31, 2017 619 6,075 364 496 In addition, we acquired Deep Basin commitments of approximately $500 million, primarily consisting of transportation commitments on various pipelines. The effectiveness of our ICFR, which excludes the Deep Basin assets, was audited as at December 31, 2017 by PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2017. Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. CORPORATE RESPONSIBILITY We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the way we conduct our business. Our Corporate Responsibility (“CR”) policy guides our activities in the areas of: Leadership, Corporate Governance and Business Practices, People, Environmental Performance, Stakeholder and Aboriginal Engagement, and Community Involvement and Investment. We published our 2016 CR report in July 2017 to report on our management efforts and performance across the above noted areas within our CR policy, as well as other environment, social and governance topics that are important to our stakeholders. Our CR report also lists external recognition we received for our commitment to corporate responsibility, and is available on our website at cenovus.com. OUTLOOK We will continue to look for ways to increase our margins through strong operating performance and cost leadership, while delivering safe and reliable operations. Proactively managing our market access commitments and opportunities should assist with our goal of reaching a broader customer base to secure a higher sales price for our liquids production. We have reduced the amount of capital needed to sustain our base business and expand our projects, which we believe will help to ensure our financial resilience. The following outlook commentary is focused on the next twelve months. Commodity Prices Underlying our Financial Results Our crude oil pricing outlook is influenced by the following: • We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current price environment, the impact of potential supply disruptions, and the pace of growth in global demand as influenced by macro-economic events. Overall, we expect crude oil price volatility to continue and a modest price improvement in the next twelve months. OPEC’s ability to adhere to its current production cuts and the possibility of future production cuts, combined with annual increases in demand growth should support prices, constrained by the need to draw down surplus crude oil inventories and U.S. production growth; • We anticipate the Brent-WTI differential will narrow after the impacts of severe weather related incidents dissipate and as a result of the U.S. exporting crude oil to overseas markets. Overall, the differential will likely be set by transportation costs; and • We expect that the WTI-WCS differential will widen due to Canadian supply increasing due to the resolution of production outages, oil sands supply growth and transportation constraints, partially offset by the possibility of OPEC extending production cuts. 2017 ANNUAL REPORT | 61 ) d e t a c i d n i e s i w r e h t o s s e n u l , l b b / $ S U e g a r e v a ( 70 65 60 55 50 45 40 35 Crude Oil Benchmarks Natural Gas Benchmarks ) d e t a c i d n i s a ( 3.00 2.80 2.60 2.40 2.20 2.00 1.80 1.60 1.40 1.20 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Forward Prices at December 31, 2017 Forward Prices at December 31, 2017 Brent C5 @ Edmonton WTI WCS WCS (C$/bbl) AECO (C$/MCf) NYMEX (US$/Mcf) Natural gas prices are anticipated to improve in the first quarter of 2018 with a normal winter heating season and increased U.S. natural gas exports, partially offset by expected North American natural gas supply growth. However, mild weather occurred in the first few months of winter in 2017. If these trends continue, it will put downward pressure on prices. Seasonal demand changes and refinery maintenance activity will result in fluctuations of refining crack spreads throughout 2018. The impact of potentially weaker refining crack spreads on refinery margins will be partially offset by the widening of the WTI-WCS differential, which increases the refinery feedstock cost advantage. We expect the Canadian dollar to continue to be tied to a modest improvement in crude oil prices and the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each other. The Bank of Canada raised its benchmark lending rate twice in 2017 and again in early 2018, marking a notable shift for Canada towards a tighter monetary policy. Foreign Exchange work at the Refineries. Market Access Refining 3-2-1 Crack Spread Benchmark ) l b b / $ S U e g a r e v a ( 25 20 15 10 0.81 0.80 0.79 ) 1 $ C / $ S U e g a r e v a ( Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Forward Prices at December 31, 2017 Chicago Forward Prices at December 31, 2017 US$/C$1 Key Priorities for 2018 Cost Reductions and Deleveraging Our priorities in 2018 are to further reduce costs and deleverage our balance sheet while maintaining capital discipline. We remain focused on maintaining our financial resilience and flexibility while continuing to deliver safe and reliable operations, which remains a top priority. Over the past three years, we have achieved significant improvements in our operating and sustaining capital costs. In 2018, we expect to realize additional capital, operating and general and administrative cost reductions across the Company. We expect to realize additional savings through continued improvements in areas such as drilling performance, development planning and optimized scheduling of oil sands well start-ups. Our ability to drive structural and sustainable cost and margin improvements will further support our business plan and financial resilience. quarter of 2018. We are making some significant reductions to our non-rent general and administrative costs in 2018, the majority of which will come from workforce reductions, which we expect to be substantially completed by the end of the first At December 31, 2017, through a combination of cash on hand and available capacity on our committed credit facility, we have approximately $5.1 billion of liquidity. We are currently marketing a package of non-core Deep Basin assets with production of approximately 15,000 BOE per day. We believe our liquidity position, proceeds from the asset sale and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than 2.0 times. Disciplined Capital Investment In 2018, we anticipate capital investment to be between $1.5 billion and $1.7 billion. We plan to direct the majority of our 2018 capital budget towards sustaining oil sands production, while supporting ongoing construction at the Christina Lake phase G expansion and a targeted drilling program in the Deep Basin. With integration remaining an important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain firm transportation commitments through a combination of pipelines, rail and marine access to support our growth plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage, sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce. Our exposure to the light/heavy price differentials is composed of both a global light/heavy component as well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of swings in light/heavy price differentials through the following: • Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products; Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS differential; Marketing arrangements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; and Transportation commitments and arrangements – supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets. • • • Additional natural gas and NGLs production associated with the acquisition of the Deep Basin Assets will provide improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations. 62 | CENOVUS ENERGY Crude Oil Benchmarks Natural Gas Benchmarks Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Forward Prices at December 31, 2017 Forward Prices at December 31, 2017 Brent C5 @ Edmonton WTI WCS WCS (C$/bbl) AECO (C$/MCf) NYMEX (US$/Mcf) Natural gas prices are anticipated to improve in the first quarter of 2018 with a normal winter heating season and increased U.S. natural gas exports, partially offset by expected North American natural gas supply growth. However, mild weather occurred in the first few months of winter in 2017. If these trends continue, it will put downward pressure on prices. Seasonal demand changes and refinery maintenance activity will result in fluctuations of refining crack spreads throughout 2018. The impact of potentially weaker refining crack spreads on refinery margins will be partially offset by the widening of the WTI-WCS differential, which increases the refinery feedstock cost advantage. We expect the Canadian dollar to continue to be tied to a modest improvement in crude oil prices and the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each other. The Bank of Canada raised its benchmark lending rate twice in 2017 and again in early 2018, marking a notable shift for Canada towards a tighter monetary policy. Key Priorities for 2018 Cost Reductions and Deleveraging Our priorities in 2018 are to further reduce costs and deleverage our balance sheet while maintaining capital discipline. We remain focused on maintaining our financial resilience and flexibility while continuing to deliver safe and reliable operations, which remains a top priority. Over the past three years, we have achieved significant improvements in our operating and sustaining capital costs. In 2018, we expect to realize additional capital, operating and general and administrative cost reductions across the Company. We expect to realize additional savings through continued improvements in areas such as drilling performance, development planning and optimized scheduling of oil sands well start-ups. Our ability to drive structural and sustainable cost and margin improvements will further support our business plan and financial resilience. We are making some significant reductions to our non-rent general and administrative costs in 2018, the majority of which will come from workforce reductions, which we expect to be substantially completed by the end of the first quarter of 2018. At December 31, 2017, through a combination of cash on hand and available capacity on our committed credit facility, we have approximately $5.1 billion of liquidity. We are currently marketing a package of non-core Deep Basin assets with production of approximately 15,000 BOE per day. We believe our liquidity position, proceeds from the asset sale and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than 2.0 times. Disciplined Capital Investment In 2018, we anticipate capital investment to be between $1.5 billion and $1.7 billion. We plan to direct the majority of our 2018 capital budget towards sustaining oil sands production, while supporting ongoing construction at the Christina Lake phase G expansion and a targeted drilling program in the Deep Basin. With integration remaining an important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability work at the Refineries. Refining 3-2-1 Crack Spread Benchmark Foreign Exchange Market Access Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain firm transportation commitments through a combination of pipelines, rail and marine access to support our growth plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage, sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce. ) d e t a c i d n i s a ( 3.00 2.80 2.60 2.40 2.20 2.00 1.80 1.60 1.40 1.20 0.81 0.80 0.79 ) 1 $ C / $ S U e g a r e v a ( ) d e t a c i d n i e s i w r e h t o s s e l n u , l b b / $ S U e g a r e v a ( 70 65 60 55 50 45 40 35 ) l b b / $ S U e g a r e v a ( 25 20 15 10 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Forward Prices at December 31, 2017 Chicago Forward Prices at December 31, 2017 US$/C$1 Our exposure to the light/heavy price differentials is composed of both a global light/heavy component as well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of swings in light/heavy price differentials through the following: Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products; Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS differential; Marketing arrangements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; and Transportation commitments and arrangements – supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets. • • • • Additional natural gas and NGLs production associated with the acquisition of the Deep Basin Assets will provide improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations. 2017 ANNUAL REPORT | 63 CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2017 TABLE OF CONTENTS 65 REPORT OF MANAGEMENT 66 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 68 CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) 69 70 71 72 73 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY CONSOLIDATED STATEMENTS OF CASH FLOWS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 73 76 76 83 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY 85 5. ACQUISITION 88 6. FINANCE COSTS 88 7. FOREIGN EXCHANGE (GAIN) LOSS, NET 88 8. DIVESTITURES 88 9. OTHER (INCOME) LOSS, NET 89 10. IMPAIRMENT CHARGES AND REVERSALS 91 11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS 93 12. INCOME TAXES 95 13. PER SHARE AMOUNTS 95 14. CASH AND CASH EQUIVALENTS 95 15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES 96 16. INVENTORIES 98 19. OTHER ASSETS 98 20. GOODWILL 98 21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 98 22. CONTINGENT PAYMENT 99 23. LONG-TERM DEBT 100 24. DECOMMISSIONING LIABILITIES 101 25. OTHER LIABILITIES 101 26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS 104 27. SHARE CAPITAL 105 28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) 105 29. STOCK-BASED COMPENSATION PLANS 108 30. EMPLOYEE SALARIES AND BENEFIT EXPENSES 108 31. RELATED PARTY TRANSACTIONS 108 32. CAPITAL STRUCTURE 110 33. FINANCIAL INSTRUMENTS 112 34. RISK MANAGEMENT 114 35. SUPPLEMENTARY CASH FLOW INFORMATION 96 17. EXPLORATION AND EVALUATION ASSETS 97 18. PROPERTY, PLANT AND EQUIPMENT, NET 115 36. COMMITMENTS AND CONTINGENCIES 64 | CENOVUS ENERGY REPORT OF MANAGEMENT Management’s Responsibility for the Consolidated Financial Statements The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Management’s best judgments. The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of four independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent auditors on at least a quarterly basis to review and approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their public release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors. Management’s Assessment of Internal Control over Financial Reporting Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements. Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2017. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2017. Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at December 31, 2017 because they were acquired by the Company through a business combination in 2017. The Deep Basin total assets and total revenues excluded from Management’s assessment of internal control over financial reporting represents 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as at and for the year ended December 31, 2017. PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2017, as stated in their Report of Independent Registered Public Accounting Firm dated February 14, 2018. PricewaterhouseCoopers LLP has provided such opinions. Alexander J. Pourbaix President & Chief Executive Officer Cenovus Energy Inc. February 14, 2018 Ivor M. Ruste Executive Vice-President & Chief Financial Officer Cenovus Energy Inc. REPORT OF MANAGEMENT Management’s Responsibility for the Consolidated Financial Statements The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Management’s best judgments. The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of four independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent auditors on at least a quarterly basis to review and approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their public release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors. Management’s Assessment of Internal Control over Financial Reporting Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements. Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2017. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2017. Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at December 31, 2017 because they were acquired by the Company through a business combination in 2017. The Deep Basin total assets and total revenues excluded from Management’s assessment of internal control over financial reporting represents 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as at and for the year ended December 31, 2017. PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2017, as stated in their Report of Independent Registered Public Accounting Firm dated February 14, 2018. PricewaterhouseCoopers LLP has provided such opinions. /s/ Alexander J. Pourbaix /s/ Ivor M. Ruste Alexander J. Pourbaix President & Chief Executive Officer Cenovus Energy Inc. February 14, 2018 Ivor M. Ruste Executive Vice-President & Chief Financial Officer Cenovus Energy Inc. 2017 ANNUAL REPORT | 65 Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Alberta, Canada February 14, 2018 We have served as the Company’s auditor since 2008. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of Cenovus Energy Inc. Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries, (together the “Company”) as of December 31, 2017 and December 31, 2016, and the related Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss), Shareholders’ Equity, and Cash Flows for each of the years in the three-year period ended December 31, 2017, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2017 and December 31, 2016 and its consolidated financial performance and its consolidated cash flows for each of the years in the three-year period ended December 31, 2017 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. Basis for Opinions The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by Management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. As described in Management’s Assessment of Internal Control over Financial Reporting, Management has excluded the Deep Basin assets from its assessment of internal control over financial reporting as of December 31, 2017 because it was acquired by the Company through a business combination in 2017. We have also excluded the Deep Basin assets from our audit of internal control over financial reporting. The Deep Basin total assets and total revenues excluded from Management’s assessment and our audit of internal control over financial reporting represent 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as at and for the year ended December 31, 2017. 66 | CENOVUS ENERGY Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Alberta, Canada February 14, 2018 We have served as the Company’s auditor since 2008. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of Cenovus Energy Inc. Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries, (together the “Company”) as of December 31, 2017 and December 31, 2016, and the related Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss), Shareholders’ Equity, and Cash Flows for each of the years in the three-year period ended December 31, 2017, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2017 and December 31, 2016 and its consolidated financial performance and its consolidated cash flows for each of the years in the three-year period ended December 31, 2017 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. Basis for Opinions The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by Management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. As described in Management’s Assessment of Internal Control over Financial Reporting, Management has excluded the Deep Basin assets from its assessment of internal control over financial reporting as of December 31, 2017 because it was acquired by the Company through a business combination in 2017. We have also excluded the Deep Basin assets from our audit of internal control over financial reporting. The Deep Basin total assets and total revenues excluded from Management’s assessment and our audit of internal control over financial reporting represent 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as at and for the year ended December 31, 2017. 2017 ANNUAL REPORT | 67 CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the years ended December 31, ($ millions) Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Items That Will Not be Reclassified to Profit or Loss: Actuarial Gain (Loss) Relating to Pension and Other Post- Retirement Benefits Items That May be Reclassified to Profit or Loss: Available for Sale Financial Assets – Change in Fair Value Available for Sale Financial Assets – Reclassified to Profit or Loss Foreign Currency Translation Adjustment Total Other Comprehensive Income (Loss), Net of Tax Comprehensive Income (Loss) See accompanying Notes to Consolidated Financial Statements. Notes 28 2017 3,366 2016 (545) 2015 618 (1) 9 - (275) (267) 3,099 (3) (2) 1 (106) (110) (655) 20 6 - 587 613 1,231 For the years ended December 31, ($ millions, except per share amounts) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense General and Administrative Finance Costs Interest Income Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Transaction Costs Re-measurement of Contingent Payment Research Costs (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Earnings (Loss) From Continuing Operations Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) From Continuing Operations Net Earnings (Loss) From Discontinued Operations Net Earnings (Loss) Basic and Diluted Earnings (Loss) Per Share ($) Continuing Operations Discontinued Operations Net Earnings (Loss) Per Share Notes 2017 2016 2015 (Restated) (1) (Restated) (1) 1 1 33 18 17 6 7 5 5 5,22 8 9 12 11 13 17,314 271 17,043 8,033 3,748 1,949 1 896 1,838 888 308 645 (62) (812) (2,555) 56 (138) 36 1 (5) 2,216 (52) 2,268 1,098 3,366 2.06 0.99 3.05 11,015 9 11,006 6,978 1,715 1,239 - 401 931 2 326 390 (52) (198) - - - 36 6 34 (802) (343) (459) (86) (545) (0.55) (0.10) (0.65) 11,559 30 11,529 7,374 1,814 1,281 1 (252) 993 67 335 381 (28) 1,036 - - - 27 (2,392) 2 890 (24) 914 (296) 618 1.11 (0.36) 0.75 (1) The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11. See accompanying Notes to Consolidated Financial Statements. 68 | CENOVUS ENERGY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the years ended December 31, ($ millions) Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Items That Will Not be Reclassified to Profit or Loss: Actuarial Gain (Loss) Relating to Pension and Other Post- Retirement Benefits Items That May be Reclassified to Profit or Loss: Available for Sale Financial Assets – Change in Fair Value Available for Sale Financial Assets – Reclassified to Profit or Loss Foreign Currency Translation Adjustment Total Other Comprehensive Income (Loss), Net of Tax Comprehensive Income (Loss) See accompanying Notes to Consolidated Financial Statements. Notes 28 2017 3,366 2016 (545) 2015 618 9 (1) - (275) (267) 3,099 (3) (2) 1 (106) (110) (655) 20 6 - 587 613 1,231 CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) For the years ended December 31, ($ millions, except per share amounts) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense General and Administrative Finance Costs Interest Income Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Transaction Costs Research Costs (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Income Tax Income Tax Expense (Recovery) Earnings (Loss) From Continuing Operations Before Net Earnings (Loss) From Continuing Operations Net Earnings (Loss) From Discontinued Operations Net Earnings (Loss) Basic and Diluted Earnings (Loss) Per Share ($) Continuing Operations Discontinued Operations Net Earnings (Loss) Per Share Notes 2017 2016 2015 (Restated) (1) (Restated) (1) 1 1 33 18 17 6 7 5 5 8 9 12 11 13 17,314 271 17,043 8,033 3,748 1,949 1 896 1,838 888 308 645 (62) (812) (2,555) 56 (138) 36 1 (5) 2,216 (52) 2,268 1,098 3,366 2.06 0.99 3.05 11,015 9 11,006 6,978 1,715 1,239 - 401 931 2 326 390 (52) (198) - - - 36 6 34 (802) (343) (459) (86) (545) (0.55) (0.10) (0.65) 11,559 30 11,529 7,374 1,814 1,281 1 (252) 993 67 335 381 (28) 1,036 - - - 27 2 (2,392) 890 (24) 914 (296) 618 1.11 (0.36) 0.75 Re-measurement of Contingent Payment 5,22 (1) The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11. See accompanying Notes to Consolidated Financial Statements. 2017 ANNUAL REPORT | 69 CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY ($ millions) As at December 31, 2014 Net Earnings Other Comprehensive Income Total Comprehensive Income Common Shares Issued for Cash Common Shares Issued Pursuant to Dividend Reinvestment Plan Stock-Based Compensation Expense Dividends on Common Shares As at December 31, 2015 Net Earnings (Loss) Other Comprehensive Income (Loss) Total Comprehensive Income (Loss) Stock-Based Compensation Expense Dividends on Common Shares As at December 31, 2016 Net Earnings (Loss) Other Comprehensive Income (Loss) Total Comprehensive Income (Loss) Common Shares Issued Stock-Based Compensation Expense Dividends on Common Shares 1,463 182 - - - - - - - - - - - - - - - 5,506 (1) Accumulated Other Comprehensive Income (Loss). See accompanying Notes to Consolidated Financial Statements. 5,534 4,330 1,020 12,391 Share Capital Paid in Surplus Retained Earnings (Note 27) (Note 27) AOCI (1) (Note 28) 3,889 4,291 1,599 618 618 407 - 613 613 39 20 - - - - - - - - - - - - - - - 11 - - - - - - - - - (710) 1,507 (545) (545) (166) 796 3,366 3,366 - - - - - - - - - - - (110) (110) 910 (267) (267) Total 10,186 618 613 1,231 1,463 182 39 (710) (545) (110) (655) 20 (166) 11,590 3,366 (267) 3,099 5,506 11 (225) 19,981 5,534 4,350 As at December 31, 2017 11,040 4,361 (225) 3,937 643 CONSOLIDATED BALANCE SHEETS As at December 31, ($ millions) Assets Current Assets Cash and Cash Equivalents Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories Risk Management Assets Held for Sale Total Current Assets Exploration and Evaluation Assets Property, Plant and Equipment, Net Income Tax Receivable Risk Management Other Assets Goodwill Total Assets Liabilities and Shareholders’ Equity Current Liabilities Accounts Payable and Accrued Liabilities Contingent Payment Income Tax Payable Risk Management Liabilities Related to Assets Held for Sale Total Current Liabilities Long-Term Debt Contingent Payment Risk Management Decommissioning Liabilities Other Liabilities Deferred Income Taxes Total Liabilities Shareholders’ Equity Total Liabilities and Shareholders’ Equity Commitments and Contingencies See accompanying Notes to Consolidated Financial Statements. Approved by the Board of Directors Notes 2017 2016 610 1,830 68 1,389 63 1,048 5,008 3,673 29,596 311 2 71 2,272 40,933 2,635 38 129 1,031 603 4,436 9,513 168 20 1,029 173 5,613 20,952 19,981 40,933 14 15 16 33,34 11 1,17 1,18 33,34 19 1,20 21 22 33,34 11 23 22 33,34 24 25 12 36 3,720 1,838 6 1,237 21 - 6,822 1,585 16,426 124 3 56 242 25,258 2,266 - 112 293 - 2,671 6,332 - 22 1,847 211 2,585 13,668 11,590 25,258 /s/ Patrick D. Daniel /s/ Colin Taylor Patrick D. Daniel Director Cenovus Energy Inc. Colin Taylor Director Cenovus Energy Inc. 70 | CENOVUS ENERGY CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY ($ millions) As at December 31, 2014 Net Earnings Other Comprehensive Income Total Comprehensive Income Common Shares Issued for Cash Common Shares Issued Pursuant to Dividend Reinvestment Plan Stock-Based Compensation Expense Dividends on Common Shares As at December 31, 2015 Net Earnings (Loss) Other Comprehensive Income (Loss) Total Comprehensive Income (Loss) Stock-Based Compensation Expense Dividends on Common Shares As at December 31, 2016 Net Earnings (Loss) Other Comprehensive Income (Loss) Total Comprehensive Income (Loss) Common Shares Issued Stock-Based Compensation Expense Dividends on Common Shares As at December 31, 2017 Share Capital (Note 27) Paid in Surplus Retained Earnings (Note 27) AOCI (1) (Note 28) 3,889 - - - 1,463 182 - - 5,534 - - - - - 5,534 - - - 5,506 - - 11,040 4,291 - - - - - 39 - 4,330 - - - 20 - 4,350 - - - - 11 - 4,361 1,599 618 - 618 - - - (710) 1,507 (545) - (545) - (166) 796 3,366 - 3,366 - - (225) 3,937 407 - 613 613 - - - - 1,020 - (110) (110) - - 910 - (267) (267) - - - 643 Total 10,186 618 613 1,231 1,463 182 39 (710) 12,391 (545) (110) (655) 20 (166) 11,590 3,366 (267) 3,099 5,506 11 (225) 19,981 (1) Accumulated Other Comprehensive Income (Loss). See accompanying Notes to Consolidated Financial Statements. As at December 31, ($ millions) Assets Current Assets Cash and Cash Equivalents Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories Risk Management Assets Held for Sale Total Current Assets Exploration and Evaluation Assets Property, Plant and Equipment, Net Income Tax Receivable Risk Management Other Assets Goodwill Total Assets Liabilities and Shareholders’ Equity Current Liabilities Accounts Payable and Accrued Liabilities Liabilities Related to Assets Held for Sale Contingent Payment Income Tax Payable Risk Management Total Current Liabilities Long-Term Debt Contingent Payment Risk Management Decommissioning Liabilities Other Liabilities Deferred Income Taxes Total Liabilities Shareholders’ Equity Total Liabilities and Shareholders’ Equity Commitments and Contingencies See accompanying Notes to Consolidated Financial Statements. Approved by the Board of Directors Notes 2017 2016 610 1,830 1,389 68 63 1,048 5,008 3,673 29,596 311 2 71 2,272 40,933 2,635 38 129 1,031 603 4,436 9,513 168 20 1,029 173 5,613 20,952 19,981 40,933 14 15 16 33,34 11 1,17 1,18 33,34 19 1,20 21 22 33,34 11 33,34 23 22 24 25 12 36 3,720 1,838 1,237 6 21 - 6,822 1,585 16,426 124 3 56 242 25,258 2,266 - 112 293 - 2,671 6,332 - 22 1,847 211 2,585 13,668 11,590 25,258 Patrick D. Daniel Director Cenovus Energy Inc. Colin Taylor Director Cenovus Energy Inc. 2017 ANNUAL REPORT | 71 CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, ($ millions) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2017 Operating Activities Net Earnings (Loss) Depreciation, Depletion and Amortization Exploration Expense Deferred Income Taxes Unrealized (Gain) Loss on Risk Management Unrealized Foreign Exchange (Gain) Loss Revaluation (Gain) Re-measurement of Contingent Payment (Gain) Loss on Discontinuance (Gain) Loss on Divestiture of Assets Current Tax on Divestiture of Assets Unwinding of Discount on Decommissioning Liabilities Onerous Contract Provisions, Net of Cash Paid Other Asset Impairments Other Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Cash From Operating Activities Investing Activities Acquisition, Net of Cash Acquired Capital Expenditures – Exploration and Evaluation Assets Capital Expenditures – Property, Plant and Equipment Proceeds From Divestiture of Assets Current Tax on Divestiture of Assets Net Change in Investments and Other Net Change in Non-Cash Working Capital Cash From (Used in) Investing Activities Notes 2017 2016 2015 18 17 12 33 7 5 22 11 8 8 24 9 5 17 18 8 8 3,366 2,030 890 583 729 (857) (2,555) (138) (1,285) 1 - 128 (8) - 30 (107) 252 3,059 (14,565) (147) (1,523) 3,210 - - 159 (12,866) (545) 1,498 2 (209) 554 (189) - - - 6 - 130 53 30 93 (91) (471) 861 - (67) (967) 8 - (1) (52) (1,079) 618 2,114 138 (655) 195 1,097 - - - (2,392) 391 126 - - 59 (107) (110) 1,474 (84) (138) (1,576) 3,344 (391) 3 (270) 888 Net Cash Provided (Used) Before Financing Activities (9,807) (218) 2,362 Basin Assets were acquired on May 17, 2017. Financing Activities Net Issuance (Repayment) of Short-Term Borrowings Issuance of Long-Term Debt Net Issuance (Repayment) of Revolving Long-Term Debt Net Issuance of Debt Under Asset Sale Bridge Facility Repayment of Debt Under Asset Sale Bridge Facility Common Shares Issued, Net of Issuance Costs Dividends Paid on Common Shares Other Cash From (Used in) Financing Activities Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents, Beginning of Year Cash and Cash Equivalents, End of Year 35 23 23 23 23 23 27 13 - 3,842 32 3,569 (3,600) 2,899 (225) (2) 6,515 182 (3,110) 3,720 610 - - - - - - (166) (2) (168) 1 (385) 4,105 3,720 (25) - - - - 1,449 (528) (2) 894 (34) 3,222 883 4,105 Supplementary Cash Flow Information 35 See accompanying Notes to Consolidated Financial Statements. 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with marketing activities and refining operations in the United States (“U.S.”). Cenovus is incorporated under the Canada Business Corporations Act and its shares are listed on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2. On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) a 50 percent interest in FCCL Partnership (“FCCL”) and the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). This acquisition (the “Acquisition”) increased Cenovus’s interest in FCCL to 100 percent and expanded Cenovus’s operating areas to include more than three million net acres of land, exploration and production assets and related infrastructure and agreements in Alberta and British Columbia. The Acquisition had an effective date of January 1, 2017 (see Note 5). Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating margin. The Company’s reportable segments are:  Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. The Company’s interest in certain of its operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017.  Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth- Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep  Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S.  Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides. In 2017, Cenovus disposed of the majority of the crude oil and natural gas assets in the Company’s Conventional segment. As such, the results of operations have been classified as a discontinued operation (see Note 11). This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018. 72 | CENOVUS ENERGY CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, ($ millions) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2017 Operating Activities Net Earnings (Loss) Depreciation, Depletion and Amortization Exploration Expense Deferred Income Taxes Unrealized (Gain) Loss on Risk Management Unrealized Foreign Exchange (Gain) Loss Revaluation (Gain) Re-measurement of Contingent Payment (Gain) Loss on Discontinuance (Gain) Loss on Divestiture of Assets Current Tax on Divestiture of Assets Unwinding of Discount on Decommissioning Liabilities Onerous Contract Provisions, Net of Cash Paid Other Asset Impairments Other Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Cash From Operating Activities Investing Activities Acquisition, Net of Cash Acquired Capital Expenditures – Exploration and Evaluation Assets Capital Expenditures – Property, Plant and Equipment Proceeds From Divestiture of Assets Current Tax on Divestiture of Assets Net Change in Investments and Other Net Change in Non-Cash Working Capital Financing Activities Net Issuance (Repayment) of Short-Term Borrowings Issuance of Long-Term Debt Net Issuance (Repayment) of Revolving Long-Term Debt Net Issuance of Debt Under Asset Sale Bridge Facility Repayment of Debt Under Asset Sale Bridge Facility Common Shares Issued, Net of Issuance Costs Dividends Paid on Common Shares Other Cash From (Used in) Financing Activities Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents, Beginning of Year Cash and Cash Equivalents, End of Year Notes 2017 2016 2015 18 17 12 33 7 5 22 11 8 8 24 9 5 17 18 8 8 35 23 23 23 23 23 27 13 3,366 2,030 890 583 729 (857) (2,555) (138) (1,285) 1 - 128 (8) - 30 (107) 252 3,059 (14,565) (147) (1,523) 3,210 - - 159 - 3,842 32 3,569 (3,600) 2,899 (225) (2) 6,515 182 3,720 610 (545) 1,498 2 (209) 554 (189) - - - 6 - 130 53 30 93 (91) (471) 861 (67) (967) - 8 - (1) (52) - - - - - - (166) (2) (168) 1 4,105 3,720 618 2,114 138 (655) 195 1,097 (2,392) - - - 391 126 - - 59 (107) (110) 1,474 (84) (138) (1,576) 3,344 (391) 3 (270) 888 (25) - - - - 1,449 (528) (2) 894 (34) 3,222 883 4,105 (3,110) (385) Cash From (Used in) Investing Activities (12,866) (1,079) Net Cash Provided (Used) Before Financing Activities (9,807) (218) 2,362 Supplementary Cash Flow Information 35 See accompanying Notes to Consolidated Financial Statements. 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with marketing activities and refining operations in the United States (“U.S.”). Cenovus is incorporated under the Canada Business Corporations Act and its shares are listed on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2. On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) a 50 percent interest in FCCL Partnership (“FCCL”) and the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). This acquisition (the “Acquisition”) increased Cenovus’s interest in FCCL to 100 percent and expanded Cenovus’s operating areas to include more than three million net acres of land, exploration and production assets and related infrastructure and agreements in Alberta and British Columbia. The Acquisition had an effective date of January 1, 2017 (see Note 5). Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating margin. The Company’s reportable segments are:  Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. The Company’s interest in certain of its operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017.  Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth- Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17, 2017.  Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S.  Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides. In 2017, Cenovus disposed of the majority of the crude oil and natural gas assets in the Company’s Conventional segment. As such, the results of operations have been classified as a discontinued operation (see Note 11). This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018. 2017 ANNUAL REPORT | 73 555 41 514 - 56 250 1 - 207 331 - 655 2 220 697 67 295 (124) - 1,721 501 - - 1,815 531 - (179) 877 1,059 (404) Revenues Gross Sales Less: Royalties Expenses 7,362 230 7,132 2,929 9 2,920 3,030 29 3,001 Purchased Product Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) - 3,704 934 - 307 2,187 1,230 888 69 - - - - - - - - - - - - - - - - - - - - - - - - 9,852 - 9,852 8,439 - 8,439 8,805 - 8,805 8,476 - 772 - 7,325 - 742 - 7,709 - 754 - 6 598 215 - 383 26 346 211 - 135 (43) 385 191 - 194 The following tabular financial information presents the segmented information first by segment, then by product and geographic location. A) Results of Operations – Segment and Operational Information For the years ended December 31, 2017 Oil Sands 2016 2015 2017 2016 2015 Deep Basin Refining and Marketing 2015 2016 2017 (1) In 2017, approximately 14 percent of the natural gas produced by Cenovus’s Deep Basin Assets was sold to ConocoPhillips resulting in gross sales B) Revenues by Product For the years ended December 31, Upstream Crude Oil Natural Gas (1) NGLs Other Refining and Marketing Corporate and Eliminations Revenues From Continuing Operations of $32 million. C) Geographical Information For the years ended December 31, Canada United States Consolidated As at December 31, Canada (2) United States Consolidated Export Sales Major Customers 2017 2016 2015 2,902 2,971 7,184 235 184 43 16 - 2 9,852 (455) 8,439 (353) 17,043 11,006 2017 9,723 7,320 17,043 Revenues 2016 4,978 6,028 11,006 Non-Current Assets (1) 2017 2016 31,756 3,856 35,612 14,130 4,179 18,309 22 - 8 8,805 (277) 11,529 2015 4,729 6,800 11,529 Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers outside of Canada were $1,713 million (2016 – $974 million; 2015 – $870 million). In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2017, Cenovus had two customers (2016 – three; 2015 – three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $5,655 million and $1,964 million, respectively (2016 – $4,742 million, $1,623 million and $1,400 million; 2015 – $4,647 million, $1,705 million and $1,545 million), which are included in all of the Company’s operating segments. D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets As at December 31, 2017 2016 2017 2016 2017 2016 2017 2016 E&E PP&E Goodwill Total Assets Oil Sands Deep Basin Conventional Refining and Marketing Corporate and Eliminations 617 1,564 22,320 8,798 2,272 242 26,799 11,112 3,056 - 3,019 - - - - 21 - - - 3,080 3,967 4,273 290 275 - - - - - - - - 6,694 - 644 3,196 5,432 6,613 1,364 4,337 Consolidated 3,673 1,585 29,596 16,426 2,272 242 40,933 25,258 For the years ended December 31, 2017 2016 2015 (1) 2017 Corporate and Eliminations Consolidated 2016 2015 Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) General and Administrative Finance Costs Interest Income Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Transaction Costs Re-measurement of Contingent Payment Research Costs (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net (455) - (455) (353) - (353) (276) 17,314 271 (277) 17,043 1 11,015 9 11,006 11,559 30 11,529 (1) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), goodwill and other assets. (2) Certain crude oil and natural gas properties of the Conventional and Deep Basin segments, which reside in Canada, have been reclassified as held for sale in 2017 in current assets. 2016 includes $3.1 billion related to the Conventional segment. (443) (12) (7) - 583 62 - (638) 308 645 (62) (812) (2,555) 56 (138) 36 1 (5) (2,526) (335) 8,033 (1) 3,748 (4) 1,949 1 1 195 896 1,838 105 888 - (347) (6) (4) - 554 65 - (615) 326 390 (52) (238) (310) 335 381 (28) 308 645 (62) (812) (2,555) 56 (138) (198) 1,036 - - - 27 - - - 36 6 34 542 (2,392) 36 1 (5) (639) (2,526) 2 6,978 1,715 1,239 - 401 931 2 (260) 326 390 (52) 7,374 1,814 1,281 1 (252) 993 67 251 335 381 (28) (198) 1,036 - - - 27 (2,392) 2 (639) - - - 36 6 34 542 Earnings (Loss) From Continuing Operations Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) From Continuing Operations 2,216 (52) 2,268 (802) (343) (459) 890 (24) 914 (1) The complete results for the 2017 and 2016 Conventional segment have been classified as a discontinued operation. For the 2015 comparative period, the results of operations for certain Conventional segment royalty interest assets disposed of in 2015 have been included in the Corporate and Eliminations segment due to their immaterial nature. The results of operations are as follows: revenues – $60 million, expenses – $5 million, operating margin – $55 million, depreciation, depletion and amortization – $27 million and segment income – $28 million. 74 | CENOVUS ENERGY The following tabular financial information presents the segmented information first by segment, then by product and geographic location. A) Results of Operations – Segment and Operational Information For the years ended December 31, 2017 2016 2015 2017 2016 2015 2017 2016 2015 Oil Sands Deep Basin Refining and Marketing Transportation and Blending 3,704 1,721 1,815 Revenues Gross Sales Less: Royalties Expenses Purchased Product Operating Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) 7,362 2,929 3,030 7,132 2,920 3,001 9 - 501 - 29 - 531 - 230 - 934 - 307 2,187 1,230 888 69 (179) (404) 877 1,059 207 655 2 220 697 67 331 - 295 (124) - - - - - - - - - - - - - - - - - - - - - - - - 9,852 8,439 8,805 - - - 9,852 8,439 8,805 8,476 7,325 7,709 772 - - 6 598 215 - 383 742 - - 26 346 211 - 135 754 - - (43) 385 191 - 194 For the years ended December 31, Corporate and Eliminations Consolidated 2017 2016 2015 (1) 2017 2016 2015 Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) General and Administrative Finance Costs Interest Income Revaluation (Gain) Transaction Costs Foreign Exchange (Gain) Loss, Net Re-measurement of Contingent Payment Research Costs (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net (455) (353) (276) 17,314 11,015 11,559 - - 1 271 9 30 (455) (353) (277) 17,043 11,006 11,529 (443) (347) (335) 8,033 6,978 7,374 (12) (7) (6) (4) (1) 3,748 1,715 1,814 (4) 1,949 1,239 1,281 (638) (615) (238) (310) (260) (62) (52) (28) (62) (52) (28) (812) (198) 1,036 (812) (198) 1,036 - 554 65 - 326 390 - - - 36 1 195 105 - 335 381 1 896 1,838 888 308 645 - - - 27 2 (2,555) (138) 56 36 1 (5) - 401 931 2 326 390 - - - 36 34 542 1 (252) 993 67 251 335 381 - - - 27 2 6 (2,392) 6 (2,392) (639) (2,526) (639) (2,555) (138) 56 36 1 (5) (2,526) 34 542 Earnings (Loss) From Continuing Operations Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) From Continuing Operations 2,216 (802) (52) (343) 2,268 (459) 890 (24) 914 (1) The complete results for the 2017 and 2016 Conventional segment have been classified as a discontinued operation. For the 2015 comparative period, the results of operations for certain Conventional segment royalty interest assets disposed of in 2015 have been included in the Corporate and Eliminations segment due to their immaterial nature. The results of operations are as follows: revenues – $60 million, expenses – $5 million, operating margin – $55 million, depreciation, depletion and amortization – $27 million and segment income – $28 million. 555 41 514 - 56 250 1 - - 583 62 - 308 645 B) Revenues by Product For the years ended December 31, Upstream Crude Oil Natural Gas (1) NGLs Other Refining and Marketing Corporate and Eliminations Revenues From Continuing Operations 2017 2016 2015 7,184 235 184 43 9,852 2,902 16 - 2 8,439 (455) (353) 17,043 11,006 2,971 22 - 8 8,805 (277) 11,529 (1) In 2017, approximately 14 percent of the natural gas produced by Cenovus’s Deep Basin Assets was sold to ConocoPhillips resulting in gross sales of $32 million. C) Geographical Information For the years ended December 31, Canada United States Consolidated As at December 31, Canada (2) United States Consolidated 2017 9,723 7,320 17,043 Revenues 2016 4,978 6,028 11,006 2015 4,729 6,800 11,529 Non-Current Assets (1) 2017 2016 31,756 3,856 35,612 14,130 4,179 18,309 Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), goodwill and other assets. (1) (2) Certain crude oil and natural gas properties of the Conventional and Deep Basin segments, which reside in Canada, have been reclassified as held for sale in 2017 in current assets. 2016 includes $3.1 billion related to the Conventional segment. Export Sales Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers outside of Canada were $1,713 million (2016 – $974 million; 2015 – $870 million). Major Customers In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2017, Cenovus had two customers (2016 – three; 2015 – three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $5,655 million and $1,964 million, respectively (2016 – $4,742 million, $1,623 million and $1,400 million; 2015 – $4,647 million, $1,705 million and $1,545 million), which are included in all of the Company’s operating segments. D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets As at December 31, 2017 2016 2017 2016 2017 2016 2017 2016 E&E PP&E Goodwill Total Assets Oil Sands Deep Basin Conventional Refining and Marketing Corporate and Eliminations 617 1,564 3,056 - - - - 21 - - 22,320 3,019 - 3,967 290 8,798 - 3,080 4,273 275 2,272 - - - - 242 - - - - 26,799 6,694 644 5,432 1,364 11,112 - 3,196 6,613 4,337 Consolidated 3,673 1,585 29,596 16,426 2,272 242 40,933 25,258 2017 ANNUAL REPORT | 75 E) Capital Expenditures (1) For the years ended December 31, Capital Oil Sands Deep Basin Conventional Refining and Marketing Corporate Capital Investment Acquisition Capital Oil Sands (2) Deep Basin Conventional Refining and Marketing Total Capital Expenditures 2017 2016 2015 973 225 206 180 77 604 - 171 220 31 1,185 - 244 248 37 1,661 1,026 1,714 11,614 6,774 - - 11 - - - 3 - 1 83 20,049 1,037 1,801 (1) (2) Includes expenditures on PP&E, E&E assets and assets held for sale. In connection with the Acquisition discussed in Note 5, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017. are provided. D) Transportation and Blending 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars. These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). These Consolidated Financial Statements have been prepared in compliance with IFRS. These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Company’s accounting policies disclosed in Note 3. These Consolidated Financial Statements were approved by the Board of Directors on February 14, 2018. 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A) Principles of Consolidation The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation. Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s Refining activities are conducted through the joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets, liabilities, revenues and expenses. Prior to May 17, 2017, FCCL was accounted for as a joint operation. Subsequent to the Acquisition, Cenovus controls FCCL, and accordingly, FCCL has been consolidated. B) Foreign Currency Translation Functional and Presentation Currency The Company’s presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income (“OCI”) as cumulative translation adjustments. When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests. 76 | CENOVUS ENERGY Transactions and Balances Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period-end date. Any gains or losses are recorded in the Consolidated Statements of Earnings. C) Revenue Recognition Revenues associated with the sales of Cenovus’s crude oil, NGLs, natural gas, and petroleum and refined products are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This is generally met when title passes from the Company to its customer. Revenues from the production of crude oil, NGLs and natural gas represent the Company’s share, net of royalty payments to governments and other mineral interest owners. Processing income and revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is provided. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending, are recognized when the product is sold. E) Exploration Expense Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense. Costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense. F) Employee Benefit Plans The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component and an other post-employment benefit plan (“OPEB”). Pension expense for the defined contribution pension is recorded as the benefits are earned. The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans. Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:    Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs. Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. subsequent periods. Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded. G) Income Taxes Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date. E) Capital Expenditures (1) For the years ended December 31, Capital Oil Sands Deep Basin Conventional Refining and Marketing Corporate Capital Investment Acquisition Capital Oil Sands (2) Deep Basin Conventional Refining and Marketing Total Capital Expenditures 2017 2016 2015 1,661 1,026 1,714 973 225 206 180 77 11,614 6,774 - - 604 - 171 220 31 11 - - - 1,185 - 244 248 37 3 - 1 83 Includes expenditures on PP&E, E&E assets and assets held for sale. (1) (2) In connection with the Acquisition discussed in Note 5, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017. 20,049 1,037 1,801 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars. These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). These Consolidated Financial Statements have been prepared in compliance with IFRS. Company’s accounting policies disclosed in Note 3. These Consolidated Financial Statements were approved by the Board of Directors on February 14, 2018. 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A) Principles of Consolidation The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation. Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s Refining activities are conducted through the joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets, liabilities, revenues and expenses. Prior to May 17, 2017, FCCL was accounted for as a joint operation. Subsequent to the Acquisition, Cenovus controls FCCL, and accordingly, FCCL has been consolidated. B) Foreign Currency Translation Functional and Presentation Currency The Company’s presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income (“OCI”) as cumulative translation adjustments. When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests. Transactions and Balances Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period-end date. Any gains or losses are recorded in the Consolidated Statements of Earnings. C) Revenue Recognition Revenues associated with the sales of Cenovus’s crude oil, NGLs, natural gas, and petroleum and refined products are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This is generally met when title passes from the Company to its customer. Revenues from the production of crude oil, NGLs and natural gas represent the Company’s share, net of royalty payments to governments and other mineral interest owners. Processing income and revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is provided. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services are provided. D) Transportation and Blending The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending, are recognized when the product is sold. E) Exploration Expense Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense. Costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense. These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the F) Employee Benefit Plans The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component and an other post-employment benefit plan (“OPEB”). Pension expense for the defined contribution pension is recorded as the benefits are earned. The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans. Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:    Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs. Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods. Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded. G) Income Taxes Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date. 2017 ANNUAL REPORT | 77 Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively. Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes. Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current. H) Net Earnings per Share Amounts Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share. I) Cash and Cash Equivalents Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less. J) Inventories Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write- down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand. K) Exploration and Evaluation Assets Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable internal costs. E&E assets are not depreciated and are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired. E&E costs are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources. Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E. Any gains or losses from the divestiture of E&E assets are recognized in net earnings. L) Property, Plant and Equipment General PP&E is stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated. Any gains or losses from the divestiture of PP&E are recognized in net earnings. Development and Production Assets Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly 78 | CENOVUS ENERGY attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves. Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired. Other Upstream Assets Refining Assets Other upstream assets include information technology assets used to support the upstream business. These assets are depreciated on a straight-line basis over their useful lives of three years. The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs. Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:    Land improvements and buildings Office equipment and vehicles Refining equipment 25 to 40 years 3 to 20 years 5 to 35 years The residual value, method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate. Other Assets Costs associated with the crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 40 years. The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on a prospective basis, if appropriate. M) Impairment Non-Financial Assets PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually. If indicators of impairment exist, the recoverable amount of the cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is determined by estimating the discounted after-tax future net cash flows. For Cenovus’s upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions. E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Goodwill is allocated to the CGUs to which it contributes to the future cash flows. If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed. Impairment losses on PP&E and E&E assets are recognized in the Consolidated Statements of Earnings as additional DD&A and exploration expense, respectively. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings. Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively. Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes. Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current. H) Net Earnings per Share Amounts Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share. I) Cash and Cash Equivalents Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less. J) Inventories Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write- down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand. K) Exploration and Evaluation Assets Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable internal costs. E&E assets are not depreciated and are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired. E&E costs are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources. Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E. Any gains or losses from the divestiture of E&E assets are recognized in net earnings. L) Property, Plant and Equipment General PP&E is stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated. Any gains or losses from the divestiture of PP&E are recognized in net earnings. Development and Production Assets Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves. Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired. Other Upstream Assets Other upstream assets include information technology assets used to support the upstream business. These assets are depreciated on a straight-line basis over their useful lives of three years. Refining Assets The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs. Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:    Land improvements and buildings Office equipment and vehicles Refining equipment 25 to 40 years 3 to 20 years 5 to 35 years The residual value, method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate. Other Assets Costs associated with the crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 40 years. The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on a prospective basis, if appropriate. M) Impairment Non-Financial Assets PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually. If indicators of impairment exist, the recoverable amount of the cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is determined by estimating the discounted after-tax future net cash flows. For Cenovus’s upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions. E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Goodwill is allocated to the CGUs to which it contributes to the future cash flows. If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed. Impairment losses on PP&E and E&E assets are recognized in the Consolidated Statements of Earnings as additional DD&A and exploration expense, respectively. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings. 2017 ANNUAL REPORT | 79 Financial Assets R) Stock-Based Compensation At each reporting date, the Company assesses whether there are any indicators that its financial assets are impaired. An impairment loss is only recognized if there is objective evidence of impairment, the loss event has an impact on future cash flows and the loss can be reliably estimated. Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. For equity securities, a significant or prolonged decline in the fair value of the security below cost is evidence that the assets are impaired. An impairment loss on a financial asset carried at amortized cost is calculated as the difference between the amortized cost and the present value of the future cash flows discounted at the asset’s original effective interest rate. The carrying amount of the asset is reduced through the use of an allowance account. Impairment losses on financial assets carried at amortized cost are reversed through net earnings in subsequent periods if the amount of the loss decreases. N) Leases Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease term. Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased asset is depreciated over the shorter of the estimated useful life of the asset or the lease term. O) Business Combinations and Goodwill Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net assets acquired is credited to net earnings. At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses. Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity. When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings. P) Provisions General A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings. Decommissioning Liabilities Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset. Actual expenditures incurred are charged against the accumulated liability. Q) Share Capital Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any income taxes. 80 | CENOVUS ENERGY Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or development activities. Net Settlement Rights surplus are recorded as share capital. Tandem Stock Appreciation Rights NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black- Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock- based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the option are recorded as share capital. Performance, Restricted and Deferred Share Units PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur. S) Financial Instruments The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, investments in the equity of private companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, contingent payment, risk management liabilities, short-term borrowings and long-term debt. Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, this exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of Earnings. Financial instruments are classified as either “fair value through profit and loss”, “loans and receivables”, “held-to- maturity investments”, “available for sale financial assets” or “financial liabilities measured at amortized cost”. The Company determines the classification of its financial instruments at initial recognition. Financial instruments are initially measured at fair value except in the case of “financial liabilities measured at amortized cost”, which are initially measured at fair value net of directly attributable transaction costs. As required by IFRS, the Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:    Level 1 inputs are quoted prices in active markets for identical assets and liabilities; Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and Level 3 inputs are unobservable inputs for the asset or liability. Fair Value Through Profit or Loss Financial assets and financial liabilities at “fair value through profit or loss” are either “held-for-trading” or have been “designated at fair value through profit or loss.” In both cases, the financial assets and financial liabilities are measured at fair value with changes in fair value recognized in net earnings. Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Financial Assets R) Stock-Based Compensation At each reporting date, the Company assesses whether there are any indicators that its financial assets are impaired. An impairment loss is only recognized if there is objective evidence of impairment, the loss event has an impact on future cash flows and the loss can be reliably estimated. Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. For equity securities, a significant or prolonged decline in the fair value of the security below cost is evidence that the assets are impaired. An impairment loss on a financial asset carried at amortized cost is calculated as the difference between the amortized cost and the present value of the future cash flows discounted at the asset’s original effective interest rate. The carrying amount of the asset is reduced through the use of an allowance account. Impairment losses on financial assets carried at amortized cost are reversed through net earnings in subsequent periods if the amount of the loss decreases. N) Leases term. Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased asset is depreciated over the shorter of the estimated useful life of the asset or the lease term. O) Business Combinations and Goodwill Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net assets acquired is credited to net earnings. At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses. Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity. When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings. P) Provisions General A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings. Decommissioning Liabilities Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset. Actual expenditures incurred are charged against the accumulated liability. Q) Share Capital Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any income taxes. Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or development activities. Net Settlement Rights NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black- Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock- based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital. Tandem Stock Appreciation Rights TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the option are recorded as share capital. Performance, Restricted and Deferred Share Units PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur. S) Financial Instruments The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, investments in the equity of private companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, contingent payment, risk management liabilities, short-term borrowings and long-term debt. Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, this exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of Earnings. Financial instruments are classified as either “fair value through profit and loss”, “loans and receivables”, “held-to- maturity investments”, “available for sale financial assets” or “financial liabilities measured at amortized cost”. The Company determines the classification of its financial instruments at initial recognition. Financial instruments are initially measured at fair value except in the case of “financial liabilities measured at amortized cost”, which are initially measured at fair value net of directly attributable transaction costs. As required by IFRS, the Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:    Level 1 inputs are quoted prices in active markets for identical assets and liabilities; Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and Level 3 inputs are unobservable inputs for the asset or liability. Fair Value Through Profit or Loss Financial assets and financial liabilities at “fair value through profit or loss” are either “held-for-trading” or have been “designated at fair value through profit or loss.” In both cases, the financial assets and financial liabilities are measured at fair value with changes in fair value recognized in net earnings. Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated 2017 ANNUAL REPORT | 81 Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss on risk management. Derivative financial instruments are not used for speculative purposes. The Company has classified its contingent payment as “fair value through profit or loss.” Loans and Receivables “Loans and receivables” are financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, these assets are measured at amortized cost at the settlement date using the effective interest method of amortization. “Loans and receivables” comprise cash and cash equivalents, accounts receivable and accrued revenues, and long-term receivables. Gains and losses on “loans and receivables” are recognized in net earnings when the “loans and receivables” are derecognized or impaired. Available for Sale Financial Assets “Available for sale financial assets” are measured at fair value, with changes in fair value recognized in OCI. When an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the equity of private companies that the Company does not control or have significant influence over. Financial Liabilities Measured at Amortized Cost These financial liabilities are measured at amortized cost at the settlement date using the effective interest method of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities, short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt or as a prepayment and amortized using the effective interest method. T) Reclassification Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2017. U) Recent Accounting Pronouncements New Accounting Standards and Interpretations not yet Adopted A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates: Financial Instruments On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, the Company has elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in OCI, impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition. IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities. A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Management does not expect a material change to its impairment provision as at January 1, 2018. In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting. IFRS 9 must be adopted for years beginning on or after January 1, 2018. The Company will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will not be restated. 82 | CENOVUS ENERGY Revenue Recognition On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded. Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice. The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. Cenovus intends to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. The Company will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption. Leases On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded. IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on the Company’s Consolidated Balance Sheets due to material operating lease commitments. Cenovus will adopt IFRS 16 effective January 1, 2019. The Company intends to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available. Uncertain Tax Positions In June 2017, the IASB issued International Financial Reporting Interpretation Committee 23, “Uncertainty Over Income Tax Treatments” (“IFRIC 23”). The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements. 4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur. A) Critical Judgments in Applying Accounting Policies Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements. Joint Arrangements The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss on risk management. Derivative financial instruments are not used for speculative purposes. The Company has classified its contingent payment as “fair value through profit or loss.” Loans and Receivables “Loans and receivables” are financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, these assets are measured at amortized cost at the settlement date using the effective interest method of amortization. “Loans and receivables” comprise cash and cash equivalents, accounts receivable and accrued revenues, and long-term receivables. Gains and losses on “loans and receivables” are recognized in net earnings when the “loans and receivables” are derecognized or impaired. Available for Sale Financial Assets “Available for sale financial assets” are measured at fair value, with changes in fair value recognized in OCI. When an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the equity of private companies that the Company does not control or have significant influence over. Financial Liabilities Measured at Amortized Cost These financial liabilities are measured at amortized cost at the settlement date using the effective interest method of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities, short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt or as a prepayment and amortized using the effective interest method. T) Reclassification Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2017. U) Recent Accounting Pronouncements New Accounting Standards and Interpretations not yet Adopted A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates: Financial Instruments On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, the Company has elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in OCI, impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition. IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities. A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Management does not expect a material change to its impairment provision as at January 1, 2018. In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting. IFRS 9 must be adopted for years beginning on or after January 1, 2018. The Company will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will not be restated. Revenue Recognition On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded. Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice. The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. Cenovus intends to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. The Company will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption. Leases On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded. IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on the Company’s Consolidated Balance Sheets due to material operating lease commitments. Cenovus will adopt IFRS 16 effective January 1, 2019. The Company intends to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available. Uncertain Tax Positions In June 2017, the IASB issued International Financial Reporting Interpretation Committee 23, “Uncertainty Over Income Tax Treatments” (“IFRIC 23”). The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements. 4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur. A) Critical Judgments in Applying Accounting Policies Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements. Joint Arrangements The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation 2017 ANNUAL REPORT | 83 and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated. In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:      The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life. The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings. FCCL operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business. Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles. In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements. Exploration and Evaluation Assets The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process. Identification of Cash-Generating Units CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals. B) Key Sources of Estimation Uncertainty Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. Crude Oil and Natural Gas Reserves There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test fair value less costs to sell and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs. 84 | CENOVUS ENERGY Recoverable Amounts Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the Company’s refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets. Decommissioning Costs Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit- adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors. Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets. Income Tax Provisions Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. 5. ACQUISITION FCCL and Deep Basin Acquisition A) Summary of the Acquisition On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’ Deep Basin Assets in Alberta and British Columbia (the “Acquisition”). The Acquisition provides Cenovus with control over the Company’s oil sands operations, doubles the Company’s oil sands production, and almost doubles the Company’s proved bitumen reserves. The Deep Basin Assets provide a second core operating area with more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia. The Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the tangible and intangible assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired has been recorded as goodwill. B) Identifiable Assets Acquired and Liabilities Assumed The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect new information obtained between May 17, 2017 and December 31, 2017 about conditions that existed at the acquisition date. As a result of these adjustments, the final purchase price allocation includes an increase of $912 million to PP&E, $56 million to inventory, and $16 million to accounts receivable and accrued revenues, as well as an $822 million decrease to E&E assets. Goodwill from the Acquisition was reduced to and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Recoverable Amounts Financial Statements. Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated. In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:      The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life. The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings. FCCL operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business. Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles. In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements. Exploration and Evaluation Assets The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process. Identification of Cash-Generating Units CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals. B) Key Sources of Estimation Uncertainty Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. Crude Oil and Natural Gas Reserves There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test fair value less costs to sell and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs. Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the Company’s refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets. Decommissioning Costs Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit- adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors. Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets. Income Tax Provisions Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. 5. ACQUISITION FCCL and Deep Basin Acquisition A) Summary of the Acquisition On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’ Deep Basin Assets in Alberta and British Columbia (the “Acquisition”). The Acquisition provides Cenovus with control over the Company’s oil sands operations, doubles the Company’s oil sands production, and almost doubles the Company’s proved bitumen reserves. The Deep Basin Assets provide a second core operating area with more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia. The Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the tangible and intangible assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired has been recorded as goodwill. B) Identifiable Assets Acquired and Liabilities Assumed The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect new information obtained between May 17, 2017 and December 31, 2017 about conditions that existed at the acquisition date. As a result of these adjustments, the final purchase price allocation includes an increase of $912 million to PP&E, $56 million to inventory, and $16 million to accounts receivable and accrued revenues, as well as an $822 million decrease to E&E assets. Goodwill from the Acquisition was reduced to 2017 ANNUAL REPORT | 85 $2,030 million and the revaluation gain increased to $2,555 million. These adjustments also resulted in a $9 million increase to the deferred income tax liability. The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of the Acquisition. 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL Cash Accounts Receivable and Accrued Revenues Inventories E&E Assets PP&E Other Assets Accounts Payable and Accrued Liabilities Decommissioning Liabilities Other Liabilities Deferred Income Taxes Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin Accounts Receivable and Accrued Revenues Inventories E&E Assets PP&E Accounts Payable and Accrued Liabilities Decommissioning Liabilities Total Identifiable Net Assets Notes 17 18 24 17 18 24 880 964 345 491 22,717 27 (445) (277) (8) (2,506) 22,188 16 14 3,117 3,600 (6) (667) 6,074 28,262 The fair value of acquired accounts receivables and accrued revenues was $980 million. As at December 31, 2017, $964 million has been received and the remainder is expected to be collected. C) Total Consideration Total consideration for the Acquisition consisted of US$10.6 billion in cash and 208 million Cenovus common shares plus closing adjustments. At the same time, Cenovus agreed to make certain quarterly contingent payments to ConocoPhillips during the five years subsequent to May 17, 2017 if crude oil prices exceed a specific threshold. The following table summarizes the fair value of the consideration: Common Shares Cash Estimated Contingent Payment (Note 22) Total Consideration 2,579 15,005 17,584 361 17,945 At the date of closing, the Company issued 208 million common shares to ConocoPhillips that were accounted for at $12.40 per share, the estimated fair value for accounting purposes. Consideration paid in cash was US$10.6 billion, before closing adjustments, and was financed through a bought- deal common share offering (see Note 27) and an offering in the United States for senior unsecured notes (see Note 23). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see Note 23). The remainder of the cash purchase price was funded with cash on hand and a draw on Cenovus’s existing committed credit facility. The estimated contingent payment related to oil sands production reflects that Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. There are no maximum payment terms. The calculation of any contingent payment includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. The terms of the contingent payment agreement allow Cenovus to retain 80 percent to 85 percent of the WCS prices above $52.00 per barrel, based on gross production capacity at Foster Creek and Christina Lake at the time of the Acquisition. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further. 86 | CENOVUS ENERGY The contingent payment is accounted for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit- adjusted risk-free rate of 2.9 percent. The contingent payment will be re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (see Note 22). D) Goodwill Goodwill arising from the Acquisition has been recognized as follows: Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL Fair Value of Identifiable Net Assets Goodwill Notes 4 C 4 B (28,262) 17,945 12,347 2,030 Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL Prior to the Acquisition, Cenovus’s 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11 and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10 and, accordingly, FCCL has been consolidated from the date of acquisition. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings. The acquisition-date fair value of the previously held interest was $12.3 billion and has been included in the measurement of the total consideration transferred. The carrying value of the FCCL assets was $9.7 billion. As a result, Cenovus recognized a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) on the re-measurement to fair value of its existing interest in FCCL. Goodwill was recorded in connection with deferred tax liabilities arising from the difference between the purchase price allocated to the FCCL assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the consideration paid for FCCL included a control premium, which resulted in a higher value compared to the fair value of the net assets acquired. E) Acquisition-Related Costs The Company incurred $56 million of Acquisition-related costs, excluding common share and debt issuance costs. These costs have been included in transaction costs in the Consolidated Statements of Earnings. Debt issuance costs related to the Acquisition financing were $72 million. These costs are netted against the carrying amount of the debt and amortized using the effective interest method. F) Transitional Services Under the purchase and sales agreement, Cenovus and ConocoPhillips agreed to certain transitional services where ConocoPhillips provided certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions were in the normal course of operations and have been measured at the exchange Costs related to the transitional services of approximately $40 million were recorded in general and administrative amounts. expenses. G) Revenue and Profit Contribution May 17, 2017 to December 31, 2017. The acquired business contributed revenues of $3.3 billion and net earnings of $172 million for the period from If the closing of the Acquisition had occurred on January 1, 2017, Cenovus’s consolidated pro forma revenue and net earnings for the twelve months ended December 31, 2017 would have been $19.0 billion and $3.5 billion, respectively. These amounts have been calculated using results from the acquired business and adjusting them for:  Differences in accounting policies;     Additional finance costs that would have been incurred if the amounts drawn on the Company’s committed asset sale bridge credit facility and the senior unsecured notes issued to fund the Acquisition had occurred on January 1, 2017; Additional DD&A that would have been charged assuming the fair value adjustments to PP&E and E&E assets had applied from January 1, 2017; Accretion on the decommissioning liability if it had been assumed on January 1, 2017; and The consequential tax effects. This pro forma information is not necessarily indicative of the results that would have been obtained if the Acquisition had actually occurred on January 1, 2017. The contingent payment is accounted for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit- adjusted risk-free rate of 2.9 percent. The contingent payment will be re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (see Note 22). D) Goodwill Goodwill arising from the Acquisition has been recognized as follows: Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL Fair Value of Identifiable Net Assets Goodwill Notes 4 C 4 B 17,945 12,347 (28,262) 2,030 Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL Prior to the Acquisition, Cenovus’s 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11 and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10 and, accordingly, FCCL has been consolidated from the date of acquisition. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings. The acquisition-date fair value of the previously held interest was $12.3 billion and has been included in the measurement of the total consideration transferred. The carrying value of the FCCL assets was $9.7 billion. As a result, Cenovus recognized a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) on the re-measurement to fair value of its existing interest in FCCL. Goodwill was recorded in connection with deferred tax liabilities arising from the difference between the purchase price allocated to the FCCL assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the consideration paid for FCCL included a control premium, which resulted in a higher value compared to the fair value of the net assets acquired. C) Total Consideration E) Acquisition-Related Costs The Company incurred $56 million of Acquisition-related costs, excluding common share and debt issuance costs. These costs have been included in transaction costs in the Consolidated Statements of Earnings. Debt issuance costs related to the Acquisition financing were $72 million. These costs are netted against the carrying amount of the debt and amortized using the effective interest method. F) Transitional Services Under the purchase and sales agreement, Cenovus and ConocoPhillips agreed to certain transitional services where ConocoPhillips provided certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions were in the normal course of operations and have been measured at the exchange amounts. Costs related to the transitional services of approximately $40 million were recorded in general and administrative expenses. G) Revenue and Profit Contribution The acquired business contributed revenues of $3.3 billion and net earnings of $172 million for the period from May 17, 2017 to December 31, 2017. If the closing of the Acquisition had occurred on January 1, 2017, Cenovus’s consolidated pro forma revenue and net earnings for the twelve months ended December 31, 2017 would have been $19.0 billion and $3.5 billion, respectively. These amounts have been calculated using results from the acquired business and adjusting them for: $2,030 million and the revaluation gain increased to $2,555 million. These adjustments also resulted in a $9 million increase to the deferred income tax liability. The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL Accounts Receivable and Accrued Revenues Notes 17 18 24 17 18 24 880 964 345 491 22,717 27 (445) (277) (8) (2,506) 22,188 16 14 3,117 3,600 (6) (667) 6,074 28,262 2,579 15,005 17,584 361 17,945 the Acquisition. Cash Inventories E&E Assets PP&E Other Assets Accounts Payable and Accrued Liabilities Decommissioning Liabilities Other Liabilities Deferred Income Taxes Inventories E&E Assets PP&E Accounts Payable and Accrued Liabilities Decommissioning Liabilities Total Identifiable Net Assets Common Shares Cash Estimated Contingent Payment (Note 22) Total Consideration Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin Accounts Receivable and Accrued Revenues The fair value of acquired accounts receivables and accrued revenues was $980 million. As at December 31, 2017, $964 million has been received and the remainder is expected to be collected. Total consideration for the Acquisition consisted of US$10.6 billion in cash and 208 million Cenovus common shares plus closing adjustments. At the same time, Cenovus agreed to make certain quarterly contingent payments to ConocoPhillips during the five years subsequent to May 17, 2017 if crude oil prices exceed a specific threshold. The following table summarizes the fair value of the consideration: At the date of closing, the Company issued 208 million common shares to ConocoPhillips that were accounted for at $12.40 per share, the estimated fair value for accounting purposes. Consideration paid in cash was US$10.6 billion, before closing adjustments, and was financed through a bought- deal common share offering (see Note 27) and an offering in the United States for senior unsecured notes (see Note 23). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see Note 23). The remainder of the cash purchase price was funded with cash on hand and a draw on Cenovus’s existing committed credit facility. The estimated contingent payment related to oil sands production reflects that Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. There are no maximum payment terms. The calculation of any contingent payment includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. The terms of the contingent payment agreement allow Cenovus to retain 80 percent to 85 percent of the WCS prices above $52.00 per barrel, based on gross production capacity at Foster Creek and Christina Lake at the time of the Acquisition. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further. Additional finance costs that would have been incurred if the amounts drawn on the Company’s committed asset sale bridge credit facility and the senior unsecured notes issued to fund the Acquisition had occurred on January 1, 2017; Additional DD&A that would have been charged assuming the fair value adjustments to PP&E and E&E assets had applied from January 1, 2017; Accretion on the decommissioning liability if it had been assumed on January 1, 2017; and The consequential tax effects.  Differences in accounting policies;     This pro forma information is not necessarily indicative of the results that would have been obtained if the Acquisition had actually occurred on January 1, 2017. 2017 ANNUAL REPORT | 87 Crude-by-Rail Terminal Acquisition In August 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of $75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million, working capital of $1 million and net transportation commitments of $92 million. Transaction costs associated with the acquisition were expensed. These assets, related liabilities and results of operations are reported in the Refining and Marketing segment. 6. FINANCE COSTS For the years ended December 31, 2017 2016 2015 Interest Expense – Short-Term Borrowings and Long-Term Debt Unwinding of Discount on Decommissioning Liabilities (Note 24) Other 571 48 26 645 341 28 21 390 328 25 28 381 7. FOREIGN EXCHANGE (GAIN) LOSS, NET For the years ended December 31, 2017 2016 2015 Unrealized Foreign Exchange (Gain) Loss on Translation of: U.S. Dollar Debt Issued From Canada Other Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 8. DIVESTITURES (665) (192) (857) 45 (812) (196) 7 (189) (9) (198) 1,064 33 1,097 (61) 1,036 In 2017, the Company completed the sale of the majority of its Conventional segment crude oil and natural gas properties for gross proceeds of $3.2 billion. A net gain of $1.3 billion was recorded on the divestitures. For further information see Note 11. In 2016, the Company completed the sale of land to an unrelated third party for cash proceeds of $8 million, resulting in a loss of $5 million. The Company also sold equipment at a loss of $1 million. These assets, related liabilities and results of operations were reported in the Conventional segment. In 2015, the Company completed the sale of Heritage Royalty Limited Partnership (“HRP”), a wholly-owned subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP was a royalty business consisting of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. These assets, related liabilities and results of operations were reported in the Conventional segment. In 2017, the remaining Conventional segment was classified as a discontinued operation. The divestiture of HRP gave rise to a taxable gain for which the Company recognized a current tax expense of $391 million. The majority of HRP’s assets had been acquired at a nominal cost and, as such, had minimal benefit from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture was specifically identifiable; therefore, it was classified as an investing activity in the Consolidated Statements of Cash Flows. In addition, the Company divested of an office building in 2015, recording a gain of $16 million. 9. OTHER (INCOME) LOSS, NET As at December 31, 2016, due to the Government of Canada’s decision to reject the Northern Gateway Pipeline project, the Company wrote off $23 million of capitalized costs associated with its funding support unit in Northern Gateway Pipeline. In addition, $7 million of costs associated with termination were recorded and $7 million (2015 – $nil) of certain investments in private equity companies were written off. Clearwater Primrose Christina Lake Narrows Lake 88 | CENOVUS ENERGY 10. IMPAIRMENT CHARGES AND REVERSALS A) Cash-Generating Unit Net Impairments On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually. 2017 Upstream Impairments As indicators of impairment were noted for the Company’s upstream assets due to a decline in forward commodity prices since the Acquisition, the Company tested its upstream CGUs for impairment. As at December 31, 2017, the Company determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional DD&A in the Deep Basin segment. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan. As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately $295 million. Key Assumptions The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after- tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2017 by the IQREs. Crude Oil, NGLs and Natural Gas Prices gas reserves were: The forward prices as at December 31, 2017, used to determine future cash flows from crude oil, NGLs and natural Average Annual Increase 2022 Thereafter 71.19 66.63 83.32 3.67 2.1% 2.1% 2.1% 2.0% WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) (2) 2018 57.50 50.61 72.41 2.43 2019 60.90 56.59 74.90 2.77 2020 64.13 60.86 77.07 3.19 2021 68.33 64.56 81.07 3.48 (1) (2) Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British Thermal Units per thousand cubic feet. Discount and Inflation Rates Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at two For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill impairments for the twelve months ended December 31, 2017. percent. Sensitivities The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have on impairment testing for the following CGUs: Increase (Decrease) to Impairment Five Percent Five Percent One Percent One Percent Increase in Decrease in Increase in Decrease in the Forward the Forward the Discount the Discount Price Estimates (1) Price Estimates Rate 27 - - 312 Rate (30) - - - (56) - - - 65 - - 333 (1) The $56 million represents the impairment loss as at December 31, 2017 that could be reversed in future periods. 2016 Net Upstream Impairments As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion. Earlier in 2016 and 2015, impairment losses of $380 million and $184 million, respectively, were recorded primarily Crude-by-Rail Terminal Acquisition In August 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of $75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million, working capital of $1 million and net transportation commitments of $92 million. Transaction costs associated with the acquisition were expensed. These assets, related liabilities and results of operations are reported in the Refining and Marketing segment. 6. FINANCE COSTS For the years ended December 31, 2017 2016 2015 Interest Expense – Short-Term Borrowings and Long-Term Debt Unwinding of Discount on Decommissioning Liabilities (Note 24) Other 571 48 26 645 341 28 21 390 328 25 28 381 For the years ended December 31, 2017 2016 2015 7. FOREIGN EXCHANGE (GAIN) LOSS, NET Unrealized Foreign Exchange (Gain) Loss on Translation of: U.S. Dollar Debt Issued From Canada Other Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss (665) (192) (857) 45 (812) (196) 7 (189) (9) (198) 1,064 33 1,097 (61) 1,036 8. DIVESTITURES information see Note 11. In 2017, the Company completed the sale of the majority of its Conventional segment crude oil and natural gas properties for gross proceeds of $3.2 billion. A net gain of $1.3 billion was recorded on the divestitures. For further In 2016, the Company completed the sale of land to an unrelated third party for cash proceeds of $8 million, resulting in a loss of $5 million. The Company also sold equipment at a loss of $1 million. These assets, related liabilities and results of operations were reported in the Conventional segment. In 2015, the Company completed the sale of Heritage Royalty Limited Partnership (“HRP”), a wholly-owned subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP was a royalty business consisting of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. These assets, related liabilities and results of operations were reported in the Conventional segment. In 2017, the remaining Conventional segment was classified as a discontinued operation. The divestiture of HRP gave rise to a taxable gain for which the Company recognized a current tax expense of $391 million. The majority of HRP’s assets had been acquired at a nominal cost and, as such, had minimal benefit from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture was specifically identifiable; therefore, it was classified as an investing activity in the Consolidated Statements of Cash Flows. In addition, the Company divested of an office building in 2015, recording a gain of $16 million. 10. IMPAIRMENT CHARGES AND REVERSALS A) Cash-Generating Unit Net Impairments On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually. 2017 Upstream Impairments As indicators of impairment were noted for the Company’s upstream assets due to a decline in forward commodity prices since the Acquisition, the Company tested its upstream CGUs for impairment. As at December 31, 2017, the Company determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional DD&A in the Deep Basin segment. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan. As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately $295 million. Key Assumptions The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after- tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2017 by the IQREs. Crude Oil, NGLs and Natural Gas Prices The forward prices as at December 31, 2017, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) (2) (1) (2) Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British Thermal Units per thousand cubic feet. 2018 57.50 50.61 72.41 2.43 2019 60.90 56.59 74.90 2.77 2020 64.13 60.86 77.07 3.19 2021 68.33 64.56 81.07 3.48 Average Annual Increase Thereafter 2.1% 2.1% 2.1% 2.0% 2022 71.19 66.63 83.32 3.67 Discount and Inflation Rates Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at two percent. For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill impairments for the twelve months ended December 31, 2017. Sensitivities The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have on impairment testing for the following CGUs: 9. OTHER (INCOME) LOSS, NET As at December 31, 2016, due to the Government of Canada’s decision to reject the Northern Gateway Pipeline project, the Company wrote off $23 million of capitalized costs associated with its funding support unit in Northern Gateway Pipeline. In addition, $7 million of costs associated with termination were recorded and $7 million (2015 – $nil) of certain investments in private equity companies were written off. Clearwater Primrose Christina Lake Narrows Lake Increase (Decrease) to Impairment One Percent Increase in the Discount Rate 27 - - 312 One Percent Decrease in the Discount Rate (30) - - - Five Percent Increase in the Forward Price Estimates (1) (56) - - - Five Percent Decrease in the Forward Price Estimates 65 - - 333 (1) The $56 million represents the impairment loss as at December 31, 2017 that could be reversed in future periods. 2016 Net Upstream Impairments As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion. Earlier in 2016 and 2015, impairment losses of $380 million and $184 million, respectively, were recorded primarily 2017 ANNUAL REPORT | 89 due to a decline in long-term heavy crude oil prices and a slowing of the development plan. In the fourth quarter of 2016, the Company reversed $400 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal arose due to the increase in the CGU’s estimated recoverable amount caused by an average reduction in expected future operating costs of five percent and lower future development costs, partially offset by a decline in estimated reserves. The impairment losses and subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). The Northern Alberta CGU included the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage. As at December 31, 2016, the recoverable amount of the Suffield CGU PP&E was estimated to be $548 million. Earlier in 2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). The Suffield CGU included production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base. There were no goodwill impairments for the twelve months ended December 31, 2016. Key Assumptions The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. Forward prices as at December 31, 2016 used to determine future cash flows from crude oil and natural gas reserves were: WTI (US$/barrel) WCS (C$/barrel) AECO (C$/Mcf) (1) (1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet. 2017 55.00 53.70 3.40 2018 2019 2020 58.70 58.20 3.15 62.40 61.90 3.30 69.00 66.50 3.60 Average Annual Increase Thereafter 2.0% 2.0% 2.2% 2021 75.80 71.00 3.90 2015 Upstream Impairments As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount, resulting in an impairment loss of $184 million. The impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a slowing down of the development plan. This was partially offset by lower future development and operating costs. The recoverable amount was determined using FVLCOD. The fair value of producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta CGU was estimated to be approximately $1.5 billion. There were no goodwill impairments for the twelve months ended December 31, 2015. B) Asset Impairments and Writedowns Exploration and Evaluation Assets For the year ended December 31, 2017, Management wrotedown certain E&E assets, as their carrying values were not considered to be recoverable. As a result, $888 million of previously capitalized costs were recorded as exploration expense. These assets reside primarily in the Borealis CGU within the Oil Sands segment. Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects. In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the Oil Sands segment. In 2015, $138 million of previously capitalized E&E costs were written off and recorded as exploration expense. This writedown included $67 million and $71 million within the Oil Sands and Conventional segments, respectively. 90 | CENOVUS ENERGY Property, Plant and Equipment, Net In 2017, the Company recorded an impairment loss of $21 million related to equipment that was written down to its recoverable amount. The impairment loss relates to the Oil Sands segment. In 2016, the Company recorded an impairment loss of $20 million primarily related to equipment that was written down to its recoverable amount. This impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation. The Company also recorded an impairment loss of $16 million related to preliminary engineering costs associated with a project that was cancelled and equipment that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil Sands segment. Leasehold improvements of $4 million were also written off and recorded as additional DD&A in the Corporate and Eliminations segment. In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded as additional DD&A in the Oil Sands segment. The Company did not have future plans for the assets and did not believe it would recover the carrying amount through a sale. 11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS In the second quarter of 2017, the Company announced its intention to divest of its Conventional segment which included its heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and conventional crude oil, natural gas and NGLs assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were consequently presented as held for sale and the results of operations reported as a discontinued operation. A) Results of Discontinued Operations In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of $3.2 billion before closing adjustments. Details of the asset sales are as follows. On September 29, 2017, the Company completed the sale of its Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern Alberta, for cash proceeds of $975 million before closing adjustments. A before- tax loss on discontinuance of $623 million was recorded on the sale. On December 7, 2017, Cenovus completed the sale of its Palliser crude oil and natural gas operations in southern Alberta for cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion was recorded on the sale. On December 14, 2017, the Company completed the sale of its Weyburn assets in southern Saskatchewan for cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was Pelican Lake Palliser Weyburn recorded on the sale. Suffield On September 25, 2017, Cenovus entered into an agreement to sell its Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. The sale closed on January 5, 2018. The Company anticipates a before-tax gain of approximately $350 million to be recorded in 2018. The agreement includes a deferred purchase price adjustment (“DPPA”) that could provide Cenovus with purchase price adjustments of up to $36 million if the average crude oil and natural gas prices meet certain thresholds over the next two years. The DPPA is a two year agreement that commences on close. Under the purchase and sale agreement, Cenovus is entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the price of Henry Hub natural gas is above US$3.50 per million British thermal units. Monthly cash payments are capped at $375 thousand and $1.125 million for crude oil and natural gas, respectively. The DPPA will be accounted for as a financial option and fair valued at each reporting date. The fair value of the DPPA on the date of close was $7 million. due to a decline in long-term heavy crude oil prices and a slowing of the development plan. In the fourth quarter of 2016, the Company reversed $400 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal arose due to the increase in the CGU’s estimated recoverable amount caused by an average reduction in expected future operating costs of five percent and lower future development costs, partially offset by a decline in estimated reserves. The impairment losses and subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). The Northern Alberta CGU included the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage. As at December 31, 2016, the recoverable amount of the Suffield CGU PP&E was estimated to be $548 million. Earlier in 2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). The Suffield CGU included production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base. There were no goodwill impairments for the twelve months ended December 31, 2016. Key Assumptions The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. Forward prices as at December 31, 2016 used to determine future cash flows from crude oil and natural gas reserves were: WTI (US$/barrel) WCS (C$/barrel) AECO (C$/Mcf) (1) 2017 55.00 53.70 3.40 2018 2019 2020 2021 Thereafter 58.70 58.20 3.15 62.40 61.90 3.30 69.00 66.50 3.60 75.80 71.00 3.90 2.0% 2.0% 2.2% (1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet. 2015 Upstream Impairments As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount, resulting in an impairment loss of $184 million. The impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a slowing down of the development plan. This was partially offset by lower future development and operating costs. The recoverable amount was determined using FVLCOD. The fair value of producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta CGU was estimated to be approximately $1.5 billion. There were no goodwill impairments for the twelve months ended December 31, 2015. B) Asset Impairments and Writedowns Exploration and Evaluation Assets For the year ended December 31, 2017, Management wrotedown certain E&E assets, as their carrying values were not considered to be recoverable. As a result, $888 million of previously capitalized costs were recorded as exploration expense. These assets reside primarily in the Borealis CGU within the Oil Sands segment. Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects. Oil Sands segment. In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the In 2015, $138 million of previously capitalized E&E costs were written off and recorded as exploration expense. This writedown included $67 million and $71 million within the Oil Sands and Conventional segments, respectively. Property, Plant and Equipment, Net In 2017, the Company recorded an impairment loss of $21 million related to equipment that was written down to its recoverable amount. The impairment loss relates to the Oil Sands segment. In 2016, the Company recorded an impairment loss of $20 million primarily related to equipment that was written down to its recoverable amount. This impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation. The Company also recorded an impairment loss of $16 million related to preliminary engineering costs associated with a project that was cancelled and equipment that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil Sands segment. Leasehold improvements of $4 million were also written off and recorded as additional DD&A in the Corporate and Eliminations segment. In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded as additional DD&A in the Oil Sands segment. The Company did not have future plans for the assets and did not believe it would recover the carrying amount through a sale. 11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS In the second quarter of 2017, the Company announced its intention to divest of its Conventional segment which included its heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and conventional crude oil, natural gas and NGLs assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were consequently presented as held for sale and the results of operations reported as a discontinued operation. Average Annual Increase A) Results of Discontinued Operations In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of $3.2 billion before closing adjustments. Details of the asset sales are as follows. Pelican Lake On September 29, 2017, the Company completed the sale of its Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern Alberta, for cash proceeds of $975 million before closing adjustments. A before- tax loss on discontinuance of $623 million was recorded on the sale. Palliser On December 7, 2017, Cenovus completed the sale of its Palliser crude oil and natural gas operations in southern Alberta for cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion was recorded on the sale. Weyburn On December 14, 2017, the Company completed the sale of its Weyburn assets in southern Saskatchewan for cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was recorded on the sale. Suffield On September 25, 2017, Cenovus entered into an agreement to sell its Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. The sale closed on January 5, 2018. The Company anticipates a before-tax gain of approximately $350 million to be recorded in 2018. The agreement includes a deferred purchase price adjustment (“DPPA”) that could provide Cenovus with purchase price adjustments of up to $36 million if the average crude oil and natural gas prices meet certain thresholds over the next two years. The DPPA is a two year agreement that commences on close. Under the purchase and sale agreement, Cenovus is entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the price of Henry Hub natural gas is above US$3.50 per million British thermal units. Monthly cash payments are capped at $375 thousand and $1.125 million for crude oil and natural gas, respectively. The DPPA will be accounted for as a financial option and fair valued at each reporting date. The fair value of the DPPA on the date of close was $7 million. 2017 ANNUAL REPORT | 91 The following table presents the results of discontinued operations, including asset sales: For the years ended December 31, 2017 2016 2015 12. INCOME TAXES The provision for income taxes is: Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Depreciation, Depletion and Amortization Exploration Expense Finance Costs Earnings (Loss) From Discontinued Operations Before Income Tax Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) After-tax Earnings (Loss) From Discontinued Operations After-tax Gain (Loss) on Discontinuance (1) Net Earnings (Loss) From Discontinued Operations (1) Net of deferred tax expense of $347 million in 2017. B) Cash Flows From Discontinued Operations 1,309 174 1,135 167 426 18 33 491 192 2 80 217 24 33 160 938 1,098 1,267 139 1,128 186 444 12 (58) 544 567 - 102 (125) 86 (125) (86) - (86) Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are: For the years ended December 31, Cash From Operating Activities Cash From (Used in) Investing Activities Net Cash Flow C) Assets and Liabilities Held for Sale 2017 448 2,993 3,441 2016 435 (168) 267 1,648 113 1,535 229 558 17 (209) 940 1,121 71 101 (353) 145 (202) (296) - (296) 2015 778 (243) 535 In the fourth quarter of 2017, the Company announced its intention to market for sale a package of non-core Deep Basin assets in the East Clearwater area and a portion of the West Clearwater assets. The assets have been classified as held for sale and recorded at the lesser of their carrying amount and their fair value less cost to sell. Assets and liabilities held for sale also include the Suffield operations, which were sold on January 5, 2018. No impairments were recorded on the assets held for sale as at December 31, 2017. As at December 31, 2017 Conventional Deep Basin E&E Assets (Note 17) PP&E (Note 18) Decommissioning Liabilities (Note 24) - 46 46 568 434 1,002 454 149 603 For the years ended December 31, 2017 2016 2015 Current Tax Canada United States Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Tax Expense (Recovery) From Continuing Operations (217) (38) (255) 203 (52) (260) 1 (259) (84) (343) 441 (12) 429 (453) (24) In 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax purposes and prior year adjustments. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal corporate income tax rate from 35 percent to 21 percent reducing the Company’s deferred income tax liability and the impact of E&E asset writedowns. In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of the refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. This was partially offset by an increase in the deferred tax expense as a result of a two percent increase in the Alberta corporate income tax rate. The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes: For the years ended December 31, Earnings (Loss) From Continuing Operations Before Income Tax Canadian Statutory Rate 27.0% 27.0% Expected Income Tax Expense (Recovery) From Continuing Operations 598 (217) Effect of Taxes Resulting From: Foreign Tax Rate Differential Non-Taxable Capital (Gains) Losses Non-Recognition of Capital (Gains) Losses Adjustments Arising From Prior Year Tax Filings (Recognition) of Previously Unrecognized Capital Losses (Recognition) of U.S. Tax Basis Change in Statutory Rate Non-Deductible Expenses Other As at December 31, Deferred Income Tax Liabilities Deferred Tax Liabilities to be Settled Within 12 Months Deferred Tax Liabilities to be Settled After More Than 12 Months Deferred Income Tax Assets Deferred Tax Assets to be Recovered Within 12 Months Deferred Tax Assets to be Recovered After More Than 12 Months Net Deferred Income Tax Liability Total Tax Expense (Recovery) From Continuing Operations Effective Tax Rate (2.3)% 42.8% (2.7)% The analysis of deferred income tax liabilities and deferred income tax assets is as follows: 2017 2016 2017 2,216 (17) (148) (118) (41) (68) - (275) (5) 22 (52) 2016 (802) (46) (26) (26) (46) - - - 5 13 (343) 186 6,229 6,415 (374) (428) (802) 5,613 2015 890 26.1% 232 (41) 137 135 (55) (149) (415) 114 7 11 (24) 6 3,147 3,153 (117) (451) (568) 2,585 The deferred income tax assets and liabilities to be settled within 12 months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year. 92 | CENOVUS ENERGY The following table presents the results of discontinued operations, including asset sales: For the years ended December 31, 2017 2016 2015 12. INCOME TAXES The provision for income taxes is: Revenues Gross Sales Less: Royalties Expenses Operating Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Depreciation, Depletion and Amortization Exploration Expense Finance Costs 1,309 174 1,135 167 426 18 33 491 192 2 80 217 24 33 160 938 2017 448 2,993 3,441 1,267 139 1,128 186 444 12 (58) 544 567 - 102 (125) 86 (125) (86) - (86) 2016 435 (168) 267 1,648 113 1,535 229 558 17 (209) 940 1,121 71 101 (353) 145 (202) (296) - (296) 2015 778 (243) 535 Earnings (Loss) From Discontinued Operations Before Income Tax Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) After-tax Earnings (Loss) From Discontinued Operations After-tax Gain (Loss) on Discontinuance (1) Net Earnings (Loss) From Discontinued Operations 1,098 (1) Net of deferred tax expense of $347 million in 2017. B) Cash Flows From Discontinued Operations Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are: For the years ended December 31, Cash From Operating Activities Cash From (Used in) Investing Activities Net Cash Flow C) Assets and Liabilities Held for Sale In the fourth quarter of 2017, the Company announced its intention to market for sale a package of non-core Deep Basin assets in the East Clearwater area and a portion of the West Clearwater assets. The assets have been classified as held for sale and recorded at the lesser of their carrying amount and their fair value less cost to sell. Assets and liabilities held for sale also include the Suffield operations, which were sold on January 5, 2018. No impairments were recorded on the assets held for sale as at December 31, 2017. As at December 31, 2017 Conventional Deep Basin E&E Assets PP&E (Note 17) (Note 18) Liabilities (Note 24) Decommissioning - 46 46 568 434 1,002 454 149 603 For the years ended December 31, 2017 2016 2015 Current Tax Canada United States Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Tax Expense (Recovery) From Continuing Operations (217) (38) (255) 203 (52) (260) 1 (259) (84) (343) 441 (12) 429 (453) (24) In 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax purposes and prior year adjustments. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal corporate income tax rate from 35 percent to 21 percent reducing the Company’s deferred income tax liability and the impact of E&E asset writedowns. In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of the refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. This was partially offset by an increase in the deferred tax expense as a result of a two percent increase in the Alberta corporate income tax rate. The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes: For the years ended December 31, Earnings (Loss) From Continuing Operations Before Income Tax Canadian Statutory Rate Expected Income Tax Expense (Recovery) From Continuing Operations 2017 2016 2,216 27.0% 598 (802) 27.0% (217) 2015 890 26.1% 232 Effect of Taxes Resulting From: Foreign Tax Rate Differential Non-Taxable Capital (Gains) Losses Non-Recognition of Capital (Gains) Losses Adjustments Arising From Prior Year Tax Filings (Recognition) of Previously Unrecognized Capital Losses (Recognition) of U.S. Tax Basis Change in Statutory Rate Non-Deductible Expenses Other Total Tax Expense (Recovery) From Continuing Operations (17) (148) (118) (41) (68) - (275) (5) 22 (52) (46) (26) (26) (46) - - - 5 13 (343) (41) 137 135 (55) (149) (415) 114 7 11 (24) Effective Tax Rate (2.3)% 42.8% (2.7)% The analysis of deferred income tax liabilities and deferred income tax assets is as follows: As at December 31, Deferred Income Tax Liabilities Deferred Tax Liabilities to be Settled Within 12 Months Deferred Tax Liabilities to be Settled After More Than 12 Months Deferred Income Tax Assets Deferred Tax Assets to be Recovered Within 12 Months Deferred Tax Assets to be Recovered After More Than 12 Months Net Deferred Income Tax Liability 2017 2016 186 6,229 6,415 (374) (428) (802) 5,613 6 3,147 3,153 (117) (451) (568) 2,585 The deferred income tax assets and liabilities to be settled within 12 months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year. 2017 ANNUAL REPORT | 93 The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is: 13. PER SHARE AMOUNTS Deferred Income Tax Liabilities As at December 31, 2015 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Purchase Price Allocation Charged (Credited) to OCI As at December 31, 2017 Deferred Income Tax Assets As at December 31, 2015 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Share Capital Charged (Credited) to OCI As at December 31, 2017 Net Deferred Income Tax Liabilities Timing of Partnership Items Risk Management - - - - 164 - - 164 82 (76) - 6 11 - - 17 PP&E 3,052 118 (24) 3,146 625 2,506 (45) 6,232 Other 17 (16) - 1 1 - - 2 Total 3,151 26 (24) 3,153 801 2,506 (45) 6,415 Unused Tax Losses Timing of Partnership Items Risk Management Other Total (172) (102) 4 (270) 67 - 12 (191) (36) 36 - - - - - - (8) (77) - (85) (198) - - (119) (92) (2) (213) (87) (28) - (335) (235) 2 (568) (218) (28) 12 (283) (328) (802) Net Deferred Income Tax Liabilities as at December 31, 2015 Charged (Credited) to Earnings Charged (Credited) to OCI Net Deferred Income Tax Liabilities as at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Purchase Price Allocation Charged (Credited) to Share Capital Charged (Credited) to OCI Net Deferred Income Tax Liabilities as at December 31, 2017 Total 2,816 (209) (22) 2,585 583 2,506 (28) (33) 5,613 No deferred tax liability has been recognized as at December 31, 2017 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. In 2016, the Company had temporary differences of $7,457 million in respect of these investments where, on dissolution or sale, a tax liability might have existed. The Company has 100 percent control of that investment as of May 17, 2017. The approximate amounts of tax pools available, including tax losses, are: As at December 31, Canada United States 2017 8,317 1,714 10,031 2016 4,273 2,036 6,309 As at December 31, 2017, the above tax pools included $73 million (2016 – $46 million) of Canadian non-capital losses and $593 million (2016 – $623 million) of U.S. federal net operating losses. These losses expire no earlier than 2025. Also included in the December 31, 2017 tax pools are Canadian net capital losses totaling $8 million (2016 – $43 million), which are available for carry forward to reduce future capital gains. All of these net capital losses are unrecognized as a deferred income tax asset as at December 31, 2017 (2016 – $40 million). Recognition is dependent on future capital gains. The Company has not recognized $293 million (2016 – $730 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt. 94 | CENOVUS ENERGY A) Net Earnings (Loss) Per Share — Basic and Diluted For the years ended December 31, 2017 2016 2015 Earnings (Loss) From: Continuing Operations Discontinued Operations Net Earnings (Loss) Basic and Diluted Earnings (Loss) Per Share From: ($) Continuing Operations Discontinued Operations Net Earnings (Loss) Per Share 2,268 1,098 3,366 2.06 0.99 3.05 (459) (86) (545) (0.55) (0.10) (0.65) 914 (296) 618 1.11 (0.36) 0.75 Weighted Average Number of Shares (millions) 1,102.5 833.3 818.7 As at December 31, 2017, 43 million NSRs (2016 – 42 million) and 81 thousand TSARs (2016 – 3 million) were excluded from the diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceed the market price of Cenovus’s common shares. These instruments could potentially dilute earnings per share in the future. For further information on the Company’s stock-based compensation plans, see Note 29. B) Dividends Per Share For the year ended December 31, 2017, the Company paid dividends of $225 million or $0.20 per share, all of which were paid in cash (2016 – $166 million or $0.20 per share, all of which were paid in cash; 2015 – $710 million or $0.8524 per share, including cash dividends of $528 million). The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2018, to common shareholders of record as of March 15, 2018. 14. CASH AND CASH EQUIVALENTS As at December 31, Cash Short-Term Investments 15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES As at December 31, Accruals Prepaids and Deposits Partner Advances Note Receivable From Partner (1) Trade Other Joint Operations Receivables 2017 547 63 610 2017 1,379 64 94 - 193 51 49 2016 542 3,178 3,720 2016 1,606 127 - 50 29 11 15 (1) Note receivable from partner was interest bearing at a rate of 1.6783 percent per annum. 1,830 1,838 The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of 13. PER SHARE AMOUNTS balances within the same tax jurisdiction, is: Deferred Income Tax Liabilities PP&E Items Management Other Timing of Partnership Risk Deferred Income Tax Assets Losses Items Management Other Total Unused Tax Partnership Risk Timing of As at December 31, 2015 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2017 Charged (Credited) to Purchase Price Allocation As at December 31, 2015 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Share Capital Charged (Credited) to OCI As at December 31, 2017 Net Deferred Income Tax Liabilities 3,052 118 (24) 3,146 625 2,506 (45) 6,232 (172) (102) (270) 4 67 - 12 (191) - - - - - - 164 164 (36) 36 - - - - - - 82 (76) 17 (16) 11 - 6 - - 17 - 1 1 - - 2 (8) (77) (85) (198) - - - (119) (92) (2) (213) (87) (28) - (283) (328) (802) Net Deferred Income Tax Liabilities as at December 31, 2015 Charged (Credited) to Earnings Charged (Credited) to OCI Net Deferred Income Tax Liabilities as at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Purchase Price Allocation Charged (Credited) to Share Capital Charged (Credited) to OCI Net Deferred Income Tax Liabilities as at December 31, 2017 Total 3,151 26 (24) 3,153 801 2,506 (45) 6,415 (335) (235) 2 (568) (218) (28) 12 Total 2,816 (209) (22) 2,585 583 2,506 (28) (33) 5,613 No deferred tax liability has been recognized as at December 31, 2017 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. In 2016, the Company had temporary differences of $7,457 million in respect of these investments where, on dissolution or sale, a tax liability might have existed. The Company has 100 percent control of that investment as of May 17, 2017. The approximate amounts of tax pools available, including tax losses, are: As at December 31, Canada United States than 2025. As at December 31, 2017, the above tax pools included $73 million (2016 – $46 million) of Canadian non-capital losses and $593 million (2016 – $623 million) of U.S. federal net operating losses. These losses expire no earlier Also included in the December 31, 2017 tax pools are Canadian net capital losses totaling $8 million (2016 – $43 million), which are available for carry forward to reduce future capital gains. All of these net capital losses are unrecognized as a deferred income tax asset as at December 31, 2017 (2016 – $40 million). Recognition is dependent on future capital gains. The Company has not recognized $293 million (2016 – $730 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt. 2017 8,317 1,714 10,031 2016 4,273 2,036 6,309 A) Net Earnings (Loss) Per Share — Basic and Diluted For the years ended December 31, 2017 2016 2015 Earnings (Loss) From: Continuing Operations Discontinued Operations Net Earnings (Loss) 2,268 1,098 3,366 (459) (86) (545) 914 (296) 618 Weighted Average Number of Shares (millions) 1,102.5 833.3 818.7 Basic and Diluted Earnings (Loss) Per Share From: ($) Continuing Operations Discontinued Operations Net Earnings (Loss) Per Share 2.06 0.99 3.05 (0.55) (0.10) (0.65) 1.11 (0.36) 0.75 As at December 31, 2017, 43 million NSRs (2016 – 42 million) and 81 thousand TSARs (2016 – 3 million) were excluded from the diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceed the market price of Cenovus’s common shares. These instruments could potentially dilute earnings per share in the future. For further information on the Company’s stock-based compensation plans, see Note 29. B) Dividends Per Share For the year ended December 31, 2017, the Company paid dividends of $225 million or $0.20 per share, all of which were paid in cash (2016 – $166 million or $0.20 per share, all of which were paid in cash; 2015 – $710 million or $0.8524 per share, including cash dividends of $528 million). The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2018, to common shareholders of record as of March 15, 2018. 14. CASH AND CASH EQUIVALENTS As at December 31, Cash Short-Term Investments 15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES As at December 31, Accruals Prepaids and Deposits Partner Advances Note Receivable From Partner (1) Trade Joint Operations Receivables Other 2017 547 63 610 2017 1,379 64 94 - 193 51 49 2016 542 3,178 3,720 2016 1,606 127 - 50 29 11 15 (1) Note receivable from partner was interest bearing at a rate of 1.6783 percent per annum. 1,830 1,838 2017 ANNUAL REPORT | 95 16. INVENTORIES As at December 31, Product Refining and Marketing Oil Sands Deep Basin Conventional Parts and Supplies 2017 2016 894 414 2 2 77 1,006 156 - 20 55 1,389 1,237 During the year ended December 31, 2017, approximately $12,856 million of produced and purchased inventory was recorded as an expense (2016 – $9,964 million; 2015 – $10,618 million). 17. EXPLORATION AND EVALUATION ASSETS As at December 31, 2015 Additions Transfers to PP&E (Note 18) Exploration Expense (Note 10) Change in Decommissioning Liabilities As at December 31, 2016 Additions Acquisition (Note 5) (1) Transfers to Assets Held for Sale (Note 11) Transfers to PP&E (Note 18) Exploration Expense (Notes 10 and 11) Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (1) As at December 31, 2017 Total 1,575 67 (49) (2) (6) 1,585 147 3,608 (316) (6) (890) 5 19 (479) 3,673 (1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3. 18. PROPERTY, PLANT AND EQUIPMENT, NET Upstream Assets Development Other Refining & Production Upstream Equipment Other (1) Total 31,481 331 717 49 (267) (16) (23) 31,941 1,324 26,317 6 (19,719) (67) (28) (12,333) 27,441 18,908 1,173 481 (462) (4) (8) 20,088 1,653 (16,120) 77 17 (3,611) 2,104 12,573 11,853 25,337 5,206 213 - (8) (152) 5,259 168 (364) (2) (25) 1,076 209 (91) (1) - - - - - - - - - - 1,037 38 - - - (1) 1,074 89 - - - 3 1 - 4 - - - - - 1 - 38,055 970 49 (275) (169) (23) 38,607 1,581 26,317 6 (19,719) (64) (391) (12,335) 485 (462) (29) (8) 22,181 1,953 77 (16,120) (73) (3,612) 4,406 333 5,061 1,167 34,002 277 31 896 205 639 66 20,720 1,475 333 2 - - - - - - - - - - - - - - - - - - - 308 23 709 68 331 1,193 778 54 25 2 4,310 4,183 3,868 398 365 389 17,335 16,426 29,596 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION COST As at December 31, 2015 Additions Transfers From E&E Assets (Note 17) Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2016 Additions Acquisition (Note 5) (2) Transfers From E&E Assets (Note 17) Transfers to Assets Held for Sale (Note 11) Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (Note 8) (2) As at December 31, 2017 As at December 31, 2015 DD&A Impairment Losses (Note 10) Reversal of Impairment Losses (Note 10) Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2016 DD&A Impairment Losses (Note 10) Transfers to Assets Held for Sale (Note 11) Exchange Rate Movements and Other Divestitures (Note 8) (2) As at December 31, 2017 CARRYING VALUE As at December 31, 2015 As at December 31, 2016 As at December 31, 2017 As at December 31, Development and Production Refining Equipment (1) (2) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft. In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3. The carrying value of the pre-existing interest in FCCL was $8,602 million. PP&E includes the following amounts in respect of assets under construction and not subject to DD&A: 2017 1,809 131 1,940 2016 537 206 743 96 | CENOVUS ENERGY During the year ended December 31, 2017, approximately $12,856 million of produced and purchased inventory was recorded as an expense (2016 – $9,964 million; 2015 – $10,618 million). 17. EXPLORATION AND EVALUATION ASSETS COST As at December 31, 2015 Additions Transfers From E&E Assets (Note 17) Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2016 Additions Acquisition (Note 5) (2) Transfers From E&E Assets (Note 17) Transfers to Assets Held for Sale (Note 11) Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (Note 8) (2) As at December 31, 2017 16. INVENTORIES As at December 31, Product Refining and Marketing Oil Sands Deep Basin Conventional Parts and Supplies As at December 31, 2015 Additions Transfers to PP&E (Note 18) Exploration Expense (Note 10) Change in Decommissioning Liabilities As at December 31, 2016 Additions Acquisition (Note 5) (1) Transfers to Assets Held for Sale (Note 11) Transfers to PP&E (Note 18) Exploration Expense (Notes 10 and 11) Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (1) As at December 31, 2017 required by IFRS 3. 2017 2016 894 414 2 2 77 1,006 156 - 20 55 1,389 1,237 Total 1,575 67 (49) (2) (6) 1,585 147 3,608 (316) (6) (890) 5 19 (479) 3,673 (1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as 18. PROPERTY, PLANT AND EQUIPMENT, NET Upstream Assets Development & Production Other Upstream Refining Equipment Other (1) Total 31,481 331 717 49 (267) (16) (23) 31,941 1,324 26,317 6 (19,719) (67) (28) (12,333) 27,441 2 - - - - 333 - - - - - - - 5,206 213 - (8) (152) - 5,259 168 - - - - (364) (2) 1,037 38,055 38 - - (1) - 1,074 89 - - - 3 1 - 970 49 (275) (169) (23) 38,607 1,581 26,317 6 (19,719) (64) (391) (12,335) 333 5,061 1,167 34,002 277 31 - - - - 308 23 - - - - 896 205 - - (25) - 1,076 209 - - (91) (1) 639 66 4 - - - 709 68 - - 1 - 331 1,193 778 20,720 1,475 485 (462) (29) (8) 22,181 1,953 77 (16,120) (73) (3,612) 4,406 54 25 2 4,310 4,183 3,868 398 365 389 17,335 16,426 29,596 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION As at December 31, 2015 DD&A Impairment Losses (Note 10) Reversal of Impairment Losses (Note 10) Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2016 DD&A Impairment Losses (Note 10) Transfers to Assets Held for Sale (Note 11) Exchange Rate Movements and Other Divestitures (Note 8) (2) As at December 31, 2017 CARRYING VALUE As at December 31, 2015 As at December 31, 2016 As at December 31, 2017 18,908 1,173 481 (462) (4) (8) 20,088 1,653 77 (16,120) 17 (3,611) 2,104 12,573 11,853 25,337 (1) (2) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft. In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3. The carrying value of the pre-existing interest in FCCL was $8,602 million. PP&E includes the following amounts in respect of assets under construction and not subject to DD&A: As at December 31, Development and Production Refining Equipment 2017 1,809 131 1,940 2016 537 206 743 2017 ANNUAL REPORT | 97 19. OTHER ASSETS As at December 31, Equity Investments Long-Term Receivables Prepaids Other 20. GOODWILL As at December 31, Carrying Value, Beginning of Year Goodwill Recognized on Acquisition (Note 5) Carrying Value, End of Year The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is: As at December 31, Primrose (Foster Creek) (1) Christina Lake (1) 2017 1,171 1,101 2,272 2017 2016 production outages at Foster Creek and Christina Lake which may reduce the amount of a contingent payment. As at December 31, 2017, $17 million is payable under this agreement. 37 11 9 14 71 2017 242 2,030 2,272 35 15 5 1 56 2016 242 - 242 2016 242 - 242 Notes Amount 2017 2016 US$ Principal A B C - - 7,650 - - 9,597 9,597 (84) 9,513 - - 6,378 6,378 (46) 6,332 (1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans. The weighted average interest rate on outstanding debt for the year ended December 31, 2017 was 4.9 percent On April 28, 2017, Cenovus amended its existing committed credit facility to increase the capacity of the facility by $0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at December 31, 2017, there were no amounts drawn on Cenovus’s committed credit facility (2016 – $nil). (1) Goodwill recognized on the Acquisition reflects measurement period adjustments. B) Asset Sale Bridge Credit Facility For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used to test Cenovus’s goodwill for impairment as at December 31, 2017 are consistent to those disclosed in Note 10. In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017. 21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, Accruals Trade Interest Partner Advances Note Payable to Partner (1) Employee Long-Term Incentives Onerous Contract Provisions Joint Operations Payables Other (1) Note payable to partner was interest bearing at a rate of 1.6783 percent per annum. 22. CONTINGENT PAYMENT As at January 1, 2017 Initial Recognition on May 17, 2017 (Note 5) Re-measurement (1) Liabilities Settled or Payable As at December 31, 2017 Less: Current Portion Long-Term Portion 2017 2,006 337 86 94 - 52 8 12 40 2016 1,927 105 72 - 50 42 18 - 52 2,635 2,266 - 361 (138) (17) 206 38 168 (1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings. In connection with the Acquisition (see Note 5), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant US$ Principal Amount 1,300 500 450 1,200 700 1,400 750 350 1,000 7,650 2017 1,631 627 565 1,505 878 1,756 941 439 1,255 9,597 2016 1,746 671 604 - - 1,880 1,007 470 - 6,378 In connection with the Acquisition, the Company completed an offering in the U.S. on April 7, 2017 for US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017, the Company completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged for notes registered under the Securities Act of 1933 with essentially the same terms and provisions as the 2017 Notes. The Exchange Offering has been treated as a modification for accounting purposes and not an extinguishment. On October 10, 2017, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$7.5 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus is available to ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion was available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions. 98 | CENOVUS ENERGY 23. LONG-TERM DEBT As at December 31, Revolving Term Debt (1) Asset Sale Bridge Credit Facility U.S. Dollar Denominated Unsecured Notes Total Debt Principal Debt Discounts and Transaction Costs Long-Term Debt (2016 – 5.3 percent). A) Revolving Term Debt C) Unsecured Notes Unsecured notes are composed of: As at December 31, 5.70% due October 15, 2019 3.00% due August 15, 2022 3.80% due September 15, 2023 4.25% due April 15, 2027 5.25% due June 15, 2037 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 5.40% due June 15, 2047 19. OTHER ASSETS As at December 31, Equity Investments Long-Term Receivables Prepaids Other 20. GOODWILL As at December 31, Carrying Value, Beginning of Year Goodwill Recognized on Acquisition (Note 5) Carrying Value, End of Year As at December 31, Primrose (Foster Creek) (1) Christina Lake (1) As at December 31, Accruals Trade Interest Partner Advances Note Payable to Partner (1) Employee Long-Term Incentives Onerous Contract Provisions Joint Operations Payables Other 22. CONTINGENT PAYMENT As at January 1, 2017 Initial Recognition on May 17, 2017 (Note 5) Re-measurement (1) Liabilities Settled or Payable As at December 31, 2017 Less: Current Portion Long-Term Portion 21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (1) Note payable to partner was interest bearing at a rate of 1.6783 percent per annum. 2,635 2,266 (1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings. In connection with the Acquisition (see Note 5), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant 37 11 9 14 71 2017 242 2,030 2,272 2017 1,171 1,101 2,272 2017 2,006 337 86 94 - 52 8 12 40 35 15 5 1 56 2016 242 - 242 2016 242 - 242 2016 1,927 105 72 - 50 42 18 - 52 - 361 (138) (17) 206 38 168 2017 2016 production outages at Foster Creek and Christina Lake which may reduce the amount of a contingent payment. As at December 31, 2017, $17 million is payable under this agreement. 23. LONG-TERM DEBT As at December 31, Revolving Term Debt (1) Asset Sale Bridge Credit Facility U.S. Dollar Denominated Unsecured Notes Total Debt Principal Debt Discounts and Transaction Costs Long-Term Debt US$ Principal Amount Notes A B C - - 7,650 2017 2016 - - 9,597 9,597 (84) 9,513 - - 6,378 6,378 (46) 6,332 (1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans. The weighted average interest rate on outstanding debt for the year ended December 31, 2017 was 4.9 percent (2016 – 5.3 percent). The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is: A) Revolving Term Debt On April 28, 2017, Cenovus amended its existing committed credit facility to increase the capacity of the facility by $0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at December 31, 2017, there were no amounts drawn on Cenovus’s committed credit facility (2016 – $nil). (1) Goodwill recognized on the Acquisition reflects measurement period adjustments. B) Asset Sale Bridge Credit Facility For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used to test Cenovus’s goodwill for impairment as at December 31, 2017 are consistent to those disclosed in Note 10. In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017. C) Unsecured Notes Unsecured notes are composed of: As at December 31, 5.70% due October 15, 2019 3.00% due August 15, 2022 3.80% due September 15, 2023 4.25% due April 15, 2027 5.25% due June 15, 2037 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 5.40% due June 15, 2047 US$ Principal Amount 1,300 500 450 1,200 700 1,400 750 350 1,000 7,650 2017 1,631 627 565 1,505 878 1,756 941 439 1,255 9,597 2016 1,746 671 604 - - 1,880 1,007 470 - 6,378 In connection with the Acquisition, the Company completed an offering in the U.S. on April 7, 2017 for US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017, the Company completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged for notes registered under the Securities Act of 1933 with essentially the same terms and provisions as the 2017 Notes. The Exchange Offering has been treated as a modification for accounting purposes and not an extinguishment. On October 10, 2017, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$7.5 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus is available to ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion was available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions. 2017 ANNUAL REPORT | 99 As at December 31, 2017, the Company is in compliance with all of the terms of its debt agreements. 25. OTHER LIABILITIES D) Mandatory Debt Payments 2018 2019 2020 2021 2022 Thereafter US$ Principal Amount Total C$ Equivalent - 1,300 - - 500 5,850 7,650 - 1,631 - - 627 7,339 9,597 24. DECOMMISSIONING LIABILITIES The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is: Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 5) (1) Liabilities Settled Liabilities Divested (1) Transfers to Liabilities Related to Assets Held for Sale (Note 11) Change in Estimated Future Cash Flows Change in Discount Rate Unwinding of Discount on Decommissioning Liabilities Foreign Currency Translation Decommissioning Liabilities, End of Year 2017 1,847 20 944 (70) (139) (1,621) (155) 76 128 (1) 1,029 2016 2,052 11 - (51) (1) - (423) 131 130 (2) 1,847 (1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS. As at December 31, 2017, the undiscounted amount of estimated future cash flows required to settle the obligation is $3,360 million (2016 – $6,270 million), which has been discounted using a credit-adjusted risk-free rate of 5.3 percent (2016 – 5.9 percent). An inflation rate of two percent (2016 – two percent) was used to calculate the decommissioning provision. Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $40 million to $50 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from lower cost estimates. Sensitivities Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities: As at December 31, One Percent Increase One Percent Decrease 2017 2016 Credit-Adjusted Risk-Free Rate Inflation Rate Credit-Adjusted Risk-Free Rate Inflation Rate (98) 192 197 (103) (248) 317 327 (259) 100 | CENOVUS ENERGY As at December 31, Employee Long-Term Incentives Onerous Contract Provisions Other Pension and Other Post-Employment Benefit Plan (Note 26) 2017 2016 43 62 37 31 173 72 71 35 33 211 26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS The Company provides employees with a pension that includes either a defined contribution or defined benefit component and other post-employment benefit plan. Most of the employees participate in the defined contribution pension. Starting in 2012, employees who meet certain criteria may move from the current defined contribution component to a defined benefit component for their future service. The defined benefit pension provides pension benefits at retirement based on years of service and final average earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides certain retired employees with health care and dental benefits until age 65 and life insurance benefits. The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial regulator at least every three years. The most recently filed valuation was dated December 31, 2014 and the next required actuarial valuation will be as at December 31, 2017. A) Defined Benefit and OPEB Plan Obligation and Funded Status Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is: Pension Benefits OPEB 2017 2016 2017 2016 As at December 31, Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year Current Service Costs Interest Costs (1) Benefits Paid Plan Participant Contributions Past Service Costs – Curtailments Remeasurements: (Gains) Losses from Experience Adjustments (Gains) Losses from Changes in Demographic Assumptions (Gains) Losses from Changes in Financial Assumptions Defined Benefit Obligation, End of Year Plan Assets Fair Value of Plan Assets, Beginning of Year Employer Contributions Plan Participant Contributions Benefits Paid Interest Income (1) Remeasurements: Return on Plan Assets (Excluding Interest Income) Fair Value of Plan Assets, End of Year Pension and OPEB (Liability) (2) 173 14 7 (8) 2 (6) 1 - (2) 181 125 (8) 9 2 4 9 141 (40) 168 14 7 (25) 2 - - - 7 173 128 14 2 (25) 3 3 125 (48) 23 (1) (1) 2 1 - - (1) (1) 22 - - - - - - - 26 (3) 1 (1) 23 - - - - - - - - - - - - (1) Based on the discount rate of the defined benefit obligation at the beginning of the year. (2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets. In connection with the divestitures of the Company’s legacy Conventional assets, affected employees left the plans (22) (23) resulting in a curtailment gain. respectively. The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 10 years, As at December 31, 2017, the Company is in compliance with all of the terms of its debt agreements. D) Mandatory Debt Payments 2018 2019 2020 2021 2022 Thereafter US$ Principal Amount Total C$ Equivalent 1,300 1,631 - - - 500 5,850 7,650 - - - 627 7,339 9,597 2017 1,847 20 944 (70) (139) (1,621) (155) 76 128 (1) 1,029 2016 2,052 11 - (51) (1) - (423) 131 130 (2) 1,847 24. DECOMMISSIONING LIABILITIES The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is: Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 5) (1) Liabilities Settled Liabilities Divested (1) Transfers to Liabilities Related to Assets Held for Sale (Note 11) Change in Estimated Future Cash Flows Change in Discount Rate Unwinding of Discount on Decommissioning Liabilities Foreign Currency Translation Decommissioning Liabilities, End of Year (1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS. As at December 31, 2017, the undiscounted amount of estimated future cash flows required to settle the obligation is $3,360 million (2016 – $6,270 million), which has been discounted using a credit-adjusted risk-free rate of 5.3 percent (2016 – 5.9 percent). An inflation rate of two percent (2016 – two percent) was used to calculate the decommissioning provision. Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $40 million to $50 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from lower cost estimates. Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the Sensitivities decommissioning liabilities: As at December 31, One Percent Increase One Percent Decrease 2017 2016 Credit-Adjusted Credit-Adjusted Risk-Free Rate Inflation Rate Risk-Free Rate Inflation Rate (98) 192 197 (103) (248) 317 327 (259) 25. OTHER LIABILITIES As at December 31, Employee Long-Term Incentives Pension and Other Post-Employment Benefit Plan (Note 26) Onerous Contract Provisions Other 2017 2016 43 62 37 31 173 72 71 35 33 211 26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS The Company provides employees with a pension that includes either a defined contribution or defined benefit component and other post-employment benefit plan. Most of the employees participate in the defined contribution pension. Starting in 2012, employees who meet certain criteria may move from the current defined contribution component to a defined benefit component for their future service. The defined benefit pension provides pension benefits at retirement based on years of service and final average earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides certain retired employees with health care and dental benefits until age 65 and life insurance benefits. The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial regulator at least every three years. The most recently filed valuation was dated December 31, 2014 and the next required actuarial valuation will be as at December 31, 2017. A) Defined Benefit and OPEB Plan Obligation and Funded Status Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is: Pension Benefits OPEB 2017 2016 2017 2016 As at December 31, Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year Current Service Costs Interest Costs (1) Benefits Paid Plan Participant Contributions Past Service Costs – Curtailments Remeasurements: (Gains) Losses from Experience Adjustments (Gains) Losses from Changes in Demographic Assumptions (Gains) Losses from Changes in Financial Assumptions Defined Benefit Obligation, End of Year Plan Assets Fair Value of Plan Assets, Beginning of Year Employer Contributions Plan Participant Contributions Benefits Paid Interest Income (1) Remeasurements: Return on Plan Assets (Excluding Interest Income) Fair Value of Plan Assets, End of Year 173 14 7 (8) 2 (6) 1 - (2) 181 125 9 2 (8) 4 9 141 168 14 7 (25) 2 - - - 7 173 128 14 2 (25) 3 3 125 (48) 23 2 1 (1) - (1) - (1) (1) 22 - - - - - - - 26 (3) 1 (1) - - - - - 23 - - - - - - - (22) (23) Pension and OPEB (Liability) (2) (1) Based on the discount rate of the defined benefit obligation at the beginning of the year. (2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets. (40) In connection with the divestitures of the Company’s legacy Conventional assets, affected employees left the plans resulting in a curtailment gain. The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 10 years, respectively. 2017 ANNUAL REPORT | 101 B) Pension and OPEB Costs For the years ended December 31, 2017 2016 2015 2017 Pension Benefits OPEB 2016 2015 Employees participating in the defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The expected employer contributions for the year ended December 31, 2018 are $9 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded Defined Benefit Plan Cost Current Service Costs Past Service Costs – Curtailments Net Settlement Costs Net Interest Costs Remeasurements: 14 (6) - 3 14 - - 4 Return on Plan Assets (Excluding Interest Income) (9) (3) (Gains) Losses from Experience Adjustments (Gains) Losses from Changes in Demographic Assumptions 1 - (Gains) Losses from Changes in Financial Assumptions (2) Defined Benefit Plan Cost (Recovery) Defined Contribution Plan Cost Total Plan Cost 1 27 28 - - 7 22 25 47 C) Investment Objectives and Fair Value of Plan Assets 19 (5) 3 6 3 (3) - (28) (5) 29 24 2 (1) - 1 - - (1) (1) - - - (3) - - 1 - - - - (2) - (2) 3 - - 1 - - - - 4 - 4 The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories. The allocation of assets between the various types of investment funds is monitored quarterly and is re-balanced as necessary. The asset allocation structure targets an investment of 50 to 75 percent in equity securities, 25 to 35 percent in fixed income assets, zero to 15 percent in real estate assets and zero to 10 percent in cash and cash equivalents. The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods. The fair value of the plan assets is: As at December 31, Equity Funds Bond Funds Non-Invested Assets Real Estate Funds Cash and Cash Equivalents 2017 2016 89 29 11 9 3 141 73 25 13 9 5 125 Fair value of equities and bonds are based on the trading price of the underlying funds. The fair value of the non- invested assets is the discounted value of the expected future payments. The fair value of the real estate funds reflects the market value and the fund manager’s appraisal value of the assets. Equity funds do not include any direct investments in Cenovus shares. D) Funding The defined benefit pension is funded in accordance with federal and provincial government pension legislation, where applicable. Contributions are made to trust funds administered by an independent trustee. The Company’s contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at December 31, 2014, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors. 102 | CENOVUS ENERGY on an as required basis. E) Actuarial Assumptions and Sensitivities Actuarial Assumptions follows: The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as For the years ended December 31, 2017 2016 2015 2017 2016 2015 Pension Benefits OPEB Discount Rate Future Salary Growth Rate Average Longevity (years) Health Care Cost Trend Rate 3.50% 3.81% 88.0 N/A 3.75% 3.80% 87.9 N/A 4.00% 3.25% 3.80% 5.08% 88.3 88.0 3.75% 5.15% 87.9 3.75% 5.15% 88.3 N/A 6.00% 7.00% 7.00% The discount rates are determined with reference to market yields on high quality corporate debt instruments of similar duration to the benefit obligations at the end of the reporting period. The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is: 2017 2016 Increase Decrease Increase Decrease Future Salary Growth Rate Health Care Cost Trend Rate One Year Change in Assumed Life Expectancy (28) 3 1 4 36 (3) (1) (4) (25) 3 2 4 32 (3) (1) (4) The above sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, the changes in some assumptions may be correlated. The same methodologies have been used to calculate the sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied when calculating the defined benefit pension liability recorded on the Consolidated Balance Sheets. Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity risk, interest rate risk, investment risk and salary risk. The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality of plan participants both during and after their employment. An increase in the life expectancy of participants will increase the defined benefit plan obligation. Sensitivities As at December 31, One Percent Change: Discount Rate F) Risks Longevity Risk Interest Rate Risk Investment Risk A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially offset by an increase in the return on debt holdings. The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than in debt instruments and real estate. Salary Risk The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation. B) Pension and OPEB Costs Defined Benefit Plan Cost Current Service Costs Past Service Costs – Curtailments Net Settlement Costs Net Interest Costs Remeasurements: For the years ended December 31, 2017 2016 2015 2017 2015 Pension Benefits OPEB 2016 Return on Plan Assets (Excluding Interest Income) (9) (3) (Gains) Losses from Experience Adjustments (Gains) Losses from Changes in Demographic Assumptions (Gains) Losses from Changes in Financial Assumptions (2) Defined Benefit Plan Cost (Recovery) Defined Contribution Plan Cost Total Plan Cost 14 (6) - 3 1 - 1 27 28 14 - - 4 - - 7 22 25 47 19 (5) 3 6 3 (3) - (28) (5) 29 24 (1) (1) (1) 2 - 1 - - - - - (3) - - 1 - - - - - (2) (2) 3 - - 1 - - - - 4 - 4 C) Investment Objectives and Fair Value of Plan Assets The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories. The allocation of assets between the various types of investment funds is monitored quarterly and is re-balanced as necessary. The asset allocation structure targets an investment of 50 to 75 percent in equity securities, 25 to 35 percent in fixed income assets, zero to 15 percent in real estate assets and zero to 10 percent in cash and cash equivalents. change in the process used by the Company to manage these risks from prior periods. The fair value of the plan assets is: As at December 31, Equity Funds Bond Funds Non-Invested Assets Real Estate Funds Cash and Cash Equivalents 2017 2016 89 29 11 9 3 141 73 25 13 9 5 125 Fair value of equities and bonds are based on the trading price of the underlying funds. The fair value of the non- invested assets is the discounted value of the expected future payments. The fair value of the real estate funds reflects the market value and the fund manager’s appraisal value of the assets. Equity funds do not include any direct investments in Cenovus shares. D) Funding The defined benefit pension is funded in accordance with federal and provincial government pension legislation, where applicable. Contributions are made to trust funds administered by an independent trustee. The Company’s contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at December 31, 2014, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors. Employees participating in the defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The expected employer contributions for the year ended December 31, 2018 are $9 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded on an as required basis. E) Actuarial Assumptions and Sensitivities Actuarial Assumptions The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows: For the years ended December 31, 2017 2016 2015 2017 2016 2015 Pension Benefits OPEB Discount Rate Future Salary Growth Rate Average Longevity (years) Health Care Cost Trend Rate 3.50% 3.81% 88.0 N/A 3.75% 3.80% 87.9 N/A 4.00% 3.80% 88.3 N/A 3.25% 5.08% 88.0 6.00% 3.75% 5.15% 87.9 7.00% 3.75% 5.15% 88.3 7.00% The discount rates are determined with reference to market yields on high quality corporate debt instruments of similar duration to the benefit obligations at the end of the reporting period. Sensitivities The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is: The Company does not use derivative instruments to manage the risks of its plan assets. There has been no One Year Change in Assumed Life Expectancy As at December 31, One Percent Change: Discount Rate Future Salary Growth Rate Health Care Cost Trend Rate 2017 2016 Increase Decrease Increase Decrease (28) 3 1 4 36 (3) (1) (4) (25) 3 2 4 32 (3) (1) (4) The above sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, the changes in some assumptions may be correlated. The same methodologies have been used to calculate the sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied when calculating the defined benefit pension liability recorded on the Consolidated Balance Sheets. F) Risks Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity risk, interest rate risk, investment risk and salary risk. Longevity Risk The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality of plan participants both during and after their employment. An increase in the life expectancy of participants will increase the defined benefit plan obligation. Interest Rate Risk A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially offset by an increase in the return on debt holdings. Investment Risk The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than in debt instruments and real estate. Salary Risk The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation. 2017 ANNUAL REPORT | 103 27. SHARE CAPITAL A) Authorized Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles. B) Issued and Outstanding As at December 31, Outstanding, Beginning of Year Common Shares Issued, Net of Issuance Costs and Tax Common Shares Issued to ConocoPhillips (Note 5) Outstanding, End of Year 2017 2016 Number of Common Shares (thousands) 833,290 187,500 208,000 1,228,790 Number of Common Shares (thousands) 833,290 - - 833,290 Amount 5,534 2,927 2,579 11,040 Amount 5,534 - - 5,534 In connection with the Acquisition (see Note 5), Cenovus closed a bought-deal common share financing on April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs). In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until after November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with Management’s recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the then outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these common shares. There were no preferred shares outstanding as at December 31, 2017 (2016 – nil). As at December 31, 2017, there were 15 million (2016 – 12 million) common shares available for future issuance under the stock option plan. C) Paid in Surplus Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) under the plan of arrangement into two independent energy companies, Encana and Cenovus (pre- arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 29A. As at December 31, 2015 Stock-Based Compensation Expense As at December 31, 2016 Stock-Based Compensation Expense As at December 31, 2017 Pre-Arrangement Earnings Stock-Based Compensation 4,086 - 4,086 - 4,086 244 20 264 11 275 Total 4,330 20 4,350 11 4,361 28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Other Comprehensive Income (Loss), Before Tax Other Comprehensive Income (Loss), Before Tax As at December 31, 2015 Income Tax As at December 31, 2016 Income Tax As at December 31, 2017 Defined Benefit Pension Plan Foreign Currency Translation Adjustment Available for Sale Financial Assets (10) (4) 1 (13) 12 (3) (4) 1,014 (106) 908 (275) - - 633 16 (4) 3 15 (1) - 14 Total 1,020 (114) 4 910 (264) (3) 643 29. STOCK-BASED COMPENSATION PLANS A) Employee Stock Option Plan Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years. Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising the option, give the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option. Options issued by the Company under the Employee Stock Option Plan prior to February 24, 2011 have associated TSARs. In lieu of exercising the options, the TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Cenovus’s common shares at the time of exercise over the exercise price The TSARs and NSRs vest and expire under the same terms and conditions as the underlying options. The weighted average unit fair value of NSRs granted during the year ended December 31, 2017 was $3.10 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average of the option. NSRs assumptions as follows: Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Expected Life (years) 1.00% 1.13% 29.14% 3.70 (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers. 104 | CENOVUS ENERGY 27. SHARE CAPITAL A) Authorized B) Issued and Outstanding Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles. As at December 31, Outstanding, Beginning of Year Common Shares Issued, Net of Issuance Costs and Tax Common Shares Issued to ConocoPhillips (Note 5) Outstanding, End of Year Number of Common Shares (thousands) 833,290 187,500 208,000 1,228,790 2017 2016 Number of Common Shares Amount (thousands) Amount 5,534 2,927 2,579 11,040 833,290 5,534 - - - - 833,290 5,534 In connection with the Acquisition (see Note 5), Cenovus closed a bought-deal common share financing on April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs). In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until after November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with Management’s recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the then outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these common shares. There were no preferred shares outstanding as at December 31, 2017 (2016 – nil). As at December 31, 2017, there were 15 million (2016 – 12 million) common shares available for future issuance under the stock option plan. C) Paid in Surplus Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) under the plan of arrangement into two independent energy companies, Encana and Cenovus (pre- arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 29A. As at December 31, 2015 Stock-Based Compensation Expense As at December 31, 2016 Stock-Based Compensation Expense As at December 31, 2017 Pre-Arrangement Earnings Stock-Based Compensation 4,086 4,086 - - 4,086 244 20 264 11 275 Total 4,330 20 4,350 11 4,361 28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) As at December 31, 2015 Other Comprehensive Income (Loss), Before Tax Income Tax As at December 31, 2016 Other Comprehensive Income (Loss), Before Tax Income Tax As at December 31, 2017 Defined Benefit Pension Plan Foreign Currency Translation Adjustment Available for Sale Financial Assets (10) (4) 1 (13) 12 (3) (4) 1,014 (106) - 908 (275) - 633 16 (4) 3 15 (1) - 14 Total 1,020 (114) 4 910 (264) (3) 643 29. STOCK-BASED COMPENSATION PLANS A) Employee Stock Option Plan Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years. Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising the option, give the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option. Options issued by the Company under the Employee Stock Option Plan prior to February 24, 2011 have associated TSARs. In lieu of exercising the options, the TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option. The TSARs and NSRs vest and expire under the same terms and conditions as the underlying options. NSRs The weighted average unit fair value of NSRs granted during the year ended December 31, 2017 was $3.10 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Expected Life (years) (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers. 1.00% 1.13% 29.14% 3.70 2017 ANNUAL REPORT | 105 The following tables summarize information related to the NSRs: As at December 31, 2017 Outstanding, Beginning of Year Granted Exercised Forfeited Outstanding, End of Year As at December 31, 2017 Range of Exercise Price ($) 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 25.00 to 29.99 30.00 to 34.99 35.00 to 39.99 TSARs Number of NSRs (thousands) Weighted Average Exercise Price ($) 41,644 3,537 - (2,454) 42,727 30.57 14.81 - 28.27 29.40 Outstanding NSRs Exercisable NSRs Number of NSRs (thousands) Weighted Average Remaining Contractual Life (years) Weighted Average Exercise Price ($) Number of NSRs (thousands) Weighted Average Exercise Price ($) 3,319 3,313 3,723 12,115 10,419 9,838 42,727 5.4 5.2 4.1 3.1 2.2 0.8 2.8 14.80 19.51 22.25 28.38 32.64 38.19 29.40 - 995 2,254 12,106 10,419 9,838 35,612 - 19.51 22.26 28.39 32.64 38.19 31.70 The Company had a liability of $nil as at December 31, 2017 (2016 – $nil) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Cenovus’s Common Share Price ($) (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers. 1.85% 1.51% 28.89% 11.48 The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2017 was $nil (2016 – $nil). The following table summarizes information related to the TSARs held by Cenovus employees: As at December 31, 2017 Outstanding, Beginning of Year Exercised for Cash Payment Exercised as Options for Common Shares Forfeited Expired Outstanding, End of Year Number of TSARs (thousands) Weighted Average Exercise Price ($) 3,373 26.66 - - (16) (3,276) 81 - - 29.19 26.48 33.52 The market price of Cenovus’s common shares on the TSX as at December 31, 2017 was $11.48. B) Performance Share Units Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are whole share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. For a portion of PSUs, the number of PSUs eligible for payment is determined over three years based on the units granted multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three. All PSUs are eligible to vest based on the Company achieving key pre-determined performance measures. PSUs vest after three years. 106 | CENOVUS ENERGY The Company has recorded a liability of $37 million as at December 31, 2017 (2016 – $51 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2017 and 2016. The following table summarizes the information related to the PSUs held by Cenovus employees: Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs vest after three years. RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period The Company has recorded a liability of $41 million as at December 31, 2017 (2016 – $30 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2017 and they occur. 2016. The following table summarizes the information related to the RSUs held by Cenovus employees: Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment. The Company has recorded a liability of $17 million as at December 31, 2017 (2016 – $32 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant. The following table summarizes the information related to the DSUs held by Cenovus directors, officers and As at December 31, 2017 Outstanding, Beginning of Year Granted Vested and Paid Out Cancelled Units in Lieu of Dividends Outstanding, End of Year C) Restricted Share Units As at December 31, 2017 Outstanding, Beginning of Year Granted Vested and Paid Out Cancelled Units in Lieu of Dividends Outstanding, End of Year D) Deferred Share Units employees: As at December 31, 2017 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year Number of PSUs (thousands) 6,157 2,392 (451) (1,192) 112 7,018 Number of RSUs (thousands) 3,790 3,278 (101) (282) 100 6,785 Number of DSUs (thousands) 1,598 136 93 27 (414) 1,440  Number of NSRs (thousands) Weighted Average Exercise Price ($) 41,644 3,537 - (2,454) 42,727 30.57 14.81 - 28.27 29.40 Outstanding NSRs Exercisable NSRs Number of NSRs (thousands) Weighted Average Remaining Contractual Life (years) Weighted Average Exercise Price ($) Number of NSRs (thousands) Weighted Average Exercise Price ($) 3,319 3,313 3,723 12,115 10,419 9,838 42,727 5.4 5.2 4.1 3.1 2.2 0.8 2.8 14.80 19.51 22.25 28.38 32.64 38.19 29.40 - 995 2,254 12,106 10,419 9,838 35,612 - 19.51 22.26 28.39 32.64 38.19 31.70 As at December 31, 2017 Outstanding, Beginning of Year Granted Exercised Forfeited Outstanding, End of Year As at December 31, 2017 Range of Exercise Price ($) 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 25.00 to 29.99 30.00 to 34.99 35.00 to 39.99 TSARs Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Cenovus’s Common Share Price ($) As at December 31, 2017 Outstanding, Beginning of Year Exercised for Cash Payment Forfeited Expired Outstanding, End of Year Exercised as Options for Common Shares B) Performance Share Units The Company had a liability of $nil as at December 31, 2017 (2016 – $nil) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers. The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2017 was $nil (2016 – $nil). The following table summarizes information related to the TSARs held by Cenovus employees: 1.85% 1.51% 28.89% 11.48 Number of TSARs (thousands) Weighted Average Exercise Price ($) 3,373 26.66 - - (16) (3,276) 81 - - 29.19 26.48 33.52 The market price of Cenovus’s common shares on the TSX as at December 31, 2017 was $11.48. Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are whole share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. For a portion of PSUs, the number of PSUs eligible for payment is determined over three years based on the units granted multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three. All PSUs are eligible to vest based on the Company achieving key pre-determined performance measures. PSUs vest after three years. The following tables summarize information related to the NSRs: The Company has recorded a liability of $37 million as at December 31, 2017 (2016 – $51 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2017 and 2016. The following table summarizes the information related to the PSUs held by Cenovus employees: As at December 31, 2017 Outstanding, Beginning of Year Granted Vested and Paid Out Cancelled Units in Lieu of Dividends Outstanding, End of Year C) Restricted Share Units Number of PSUs (thousands) 6,157 2,392 (451) (1,192) 112 7,018 Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs vest after three years. RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period they occur. The Company has recorded a liability of $41 million as at December 31, 2017 (2016 – $30 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2017 and 2016. The following table summarizes the information related to the RSUs held by Cenovus employees: As at December 31, 2017 Outstanding, Beginning of Year Granted Vested and Paid Out Cancelled Units in Lieu of Dividends Outstanding, End of Year D) Deferred Share Units Number of RSUs (thousands) 3,790 3,278 (101) (282) 100 6,785 Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment. The Company has recorded a liability of $17 million as at December 31, 2017 (2016 – $32 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant. The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees: As at December 31, 2017 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year Number of DSUs (thousands) 1,598 136 93 27 (414) 1,440 2017 ANNUAL REPORT | 107 E) Total Stock-Based Compensation A) Net Debt to Adjusted EBITDA For the years ended December 31, 2017 2016 2015 As at December 31, 2017 2016 2015 NSRs TSARs PSUs RSUs DSUs Stock-Based Compensation Expense (Recovery) Stock-Based Compensation Costs Capitalized Total Stock-Based Compensation 9 - (7) 3 (11) (6) 3 (3) 15 (1) 13 13 7 47 12 59 30. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, 2017 2016 Salaries, Bonuses and Other Short-Term Employee Benefits Defined Contribution Pension Plan Defined Benefit Pension Plan and OPEB Stock-Based Compensation Expense (Note 29) Termination Benefits 31. RELATED PARTY TRANSACTIONS Key Management Compensation 606 19 8 (6) 19 646 500 16 11 47 19 593 27 (5) (13) 6 (5) 10 6 16 2015 534 19 17 10 43 623 Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is: For the years ended December 31, 2017 2016 2015 Net Debt to Capitalization Salaries, Director Fees and Short-Term Benefits Post-Employment Benefits Stock-Based Compensation 26 4 6 36 27 4 4 35 30 5 5 40 Post employment benefits represent the present value of future pension benefits earned during the year. Stock-based compensation includes the costs recorded during the year associated with stock options, NSRs, TSARs, PSUs, RSUs and DSUs. 32. CAPITAL STRUCTURE Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. Cenovus conducts its business and makes decisions consistent with that of an investment grade company. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within the economic cycle, Cenovus expects this ratio may periodically be above the target. Cenovus also manages its Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit facility agreement. 108 | CENOVUS ENERGY Long-Term Debt Less: Cash and Cash Equivalents Net Debt Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income DD&A E&E Impairment Income Tax Expense (Recovery) Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Re-measurement of Contingent Payment (Gain) Loss on Discontinuance (Gain) Loss on Divestitures of Assets Other (Income) Loss, Net Adjusted EBITDA (1) B) Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity 9,513 (610) 8,903 6,332 (3,720) 2,612 3,366 (545) 725 (62) 352 2,030 890 729 (812) (2,555) (138) (1,285) 1 (5) 3,236 492 (52) (382) 1,498 554 (198) 2 - - - 6 34 1,409 6,525 (4,105) 2,420 618 482 (28) (81) 2,114 138 195 1,036 - - - 2 (2,392) 2,084 2017 2016 2015 8,903 19,981 28,884 31% 2,612 11,590 14,202 18% 2,420 12,391 14,811 16% Net Debt to Adjusted EBITDA 2.8x 1.9x 1.2x (1) Calculated on a trailing twelve-month basis. Includes discontinued operations. As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8 times, which is above the Company’s target. However, it is important to note that Adjusted EBITDA is calculated on a rolling twelve month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to December 31, 2017. Net Debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower. Cenovus’s objective is to maintain a high level of capital discipline and manage its capital structure to help ensure sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facility or repay existing debt, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new debt, or issue new shares. Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at December 31, 2017, no amounts were drawn on its committed credit facility. Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is well below this limit. In addition, the Company has in place a base shelf prospectus which expires in November 2019. As at December 31, 2017, US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions. As at December 31, 2017, Cenovus is in compliance with all of the terms of its debt agreements. 30. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, 2017 2016 NSRs TSARs PSUs RSUs DSUs Stock-Based Compensation Expense (Recovery) Stock-Based Compensation Costs Capitalized Total Stock-Based Compensation Salaries, Bonuses and Other Short-Term Employee Benefits Defined Contribution Pension Plan Defined Benefit Pension Plan and OPEB Stock-Based Compensation Expense (Note 29) Termination Benefits 31. RELATED PARTY TRANSACTIONS Key Management Compensation 9 - 3 (7) (6) 3 (3) (11) 606 19 8 (6) 19 646 15 (1) 13 13 7 47 12 59 500 16 11 47 19 593 27 (5) (13) 6 (5) 10 6 16 2015 534 19 17 10 43 623 Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is: Salaries, Director Fees and Short-Term Benefits Post-Employment Benefits Stock-Based Compensation 26 4 6 36 27 4 4 35 30 5 5 40 Post employment benefits represent the present value of future pension benefits earned during the year. Stock-based compensation includes the costs recorded during the year associated with stock options, NSRs, TSARs, PSUs, RSUs and DSUs. 32. CAPITAL STRUCTURE Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. Cenovus conducts its business and makes decisions consistent with that of an investment grade company. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within the economic cycle, Cenovus expects this ratio may periodically be above the target. Cenovus also manages its Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit facility agreement. E) Total Stock-Based Compensation A) Net Debt to Adjusted EBITDA For the years ended December 31, 2017 2016 2015 As at December 31, Long-Term Debt Less: Cash and Cash Equivalents Net Debt Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income Income Tax Expense (Recovery) DD&A E&E Impairment Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Re-measurement of Contingent Payment (Gain) Loss on Discontinuance (Gain) Loss on Divestitures of Assets Other (Income) Loss, Net Adjusted EBITDA (1) 2017 2016 2015 9,513 (610) 8,903 6,332 (3,720) 2,612 6,525 (4,105) 2,420 3,366 (545) 618 725 (62) 352 2,030 890 729 (812) (2,555) (138) (1,285) 1 (5) 3,236 492 (52) (382) 1,498 2 554 (198) - - - 6 34 1,409 482 (28) (81) 2,114 138 195 1,036 - - - (2,392) 2 2,084 For the years ended December 31, 2017 2016 2015 Net Debt to Capitalization B) Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity 2017 2016 2015 8,903 19,981 28,884 31% 2,612 11,590 14,202 18% 2,420 12,391 14,811 16% Net Debt to Adjusted EBITDA 2.8x 1.9x 1.2x (1) Calculated on a trailing twelve-month basis. Includes discontinued operations. As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8 times, which is above the Company’s target. However, it is important to note that Adjusted EBITDA is calculated on a rolling twelve month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to December 31, 2017. Net Debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower. Cenovus’s objective is to maintain a high level of capital discipline and manage its capital structure to help ensure sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facility or repay existing debt, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new debt, or issue new shares. Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at December 31, 2017, no amounts were drawn on its committed credit facility. Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is well below this limit. In addition, the Company has in place a base shelf prospectus which expires in November 2019. As at December 31, 2017, US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions. As at December 31, 2017, Cenovus is in compliance with all of the terms of its debt agreements. 2017 ANNUAL REPORT | 109 33. FINANCIAL INSTRUMENTS The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, available for sale financial assets, long-term receivables, contingent payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments. A) Fair Value of Non-Derivative Financial Instruments The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments. The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments. Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2017, the carrying value of Cenovus’s debt was $9,513 million and the fair value was $10,061 million (2016 carrying value – $6,332 million; fair value – $6,539 million). Available for sale financial assets comprise private equity investments. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of available for sale financial assets: As at December 31, Fair Value, Beginning of Year Net Acquisition of Investments Change in Fair Value (1) Impairment Losses (2) Fair Value, End of Year 2017 2016 35 3 (1) - 37 42 - (4) (3) 35 (1) Changes in fair value on available for sale financial assets are recorded in OCI. (2) Impairment losses on available for sale financial assets are reclassified from OCI to profit or loss. B) Fair Value of Risk Management Assets and Liabilities The Company’s risk management assets and liabilities consist of crude oil swaps and options, as well as condensate and interest rate swaps. Crude oil, condensate and, if entered, natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including interest rate yield curves (Level 2). Summary of Unrealized Risk Management Positions As at December 31, Crude Oil Interest Rate Total Fair Value 2017 Risk Management Liability Asset 2016 Risk Management Net Asset Liability 63 2 65 1,031 20 1,051 (968) (18) (986) 21 3 24 307 8 315 Net (286) (5) (291) The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value: As at December 31, Level 2 – Prices Sourced From Observable Data or Market Corroboration 2017 (986) 2016 (291) Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. 110 | CENOVUS ENERGY liabilities: As at December 31, Fair Value of Contracts, Beginning of Year Fair Value of Contracts Realized During the Year (1) Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year Unamortized Premium on Put Options Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts Fair Value of Contracts, End of Year 2017 (291) 200 (929) 16 18 (986) 2016 271 (211) (343) - (8) (291) (1) Includes a realized loss of $33 million (2016 – $58 million gain) related to the Conventional segment which is included in discontinued operations. Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset. The following table provides a summary of the Company’s offsetting risk management positions: 2017 Risk Management 2016 Risk Management As at December 31, Asset Liability Net Asset Liability Net Recognized Risk Management Positions Gross Amount Amount Offset Statements Net Amount per Consolidated Financial 135 (70) 1,121 (986) (70) - 75 (51) 366 (51) (291) - 65 1,051 (986) 24 315 (291) The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial. Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management receivables on a particular day. As at December 31, 2017, $26 million (2016 – $84 million) was pledged as collateral, of which $nil (2016 – $18 million) could have been withdrawn. C) Fair Value of Contingent Payment The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the future expected cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 3.3 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2017, the fair value of the contingent payment was estimated to be $206 million. As at December 31, 2017, average WCS forward pricing for the remaining term of the contingent payment is US$35.51 per barrel or C$44.55 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to value the contingent payment was 20 percent and seven percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows: WCS Forward Prices WTI Option Volatility U.S. to Canadian Dollar Foreign Exchange Rate Volatility Sensitivity Range Increase Decrease  $5.00 per bbl  five percent  five percent (167) (95) 2 111 85 (27) 33. FINANCIAL INSTRUMENTS Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, available for sale financial assets, long-term receivables, contingent payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments. A) Fair Value of Non-Derivative Financial Instruments The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable these instruments. nature of these instruments. Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2017, the carrying value of Cenovus’s debt was $9,513 million and the fair value was $10,061 million (2016 carrying value – $6,332 million; fair value – $6,539 million). Available for sale financial assets comprise private equity investments. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of available for sale financial assets: As at December 31, Fair Value, Beginning of Year Net Acquisition of Investments Change in Fair Value (1) Impairment Losses (2) Fair Value, End of Year 2017 2016 35 3 - 37 (1) 42 - (4) (3) 35 (1) Changes in fair value on available for sale financial assets are recorded in OCI. (2) Impairment losses on available for sale financial assets are reclassified from OCI to profit or loss. B) Fair Value of Risk Management Assets and Liabilities The Company’s risk management assets and liabilities consist of crude oil swaps and options, as well as condensate and interest rate swaps. Crude oil, condensate and, if entered, natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including interest rate yield curves (Level 2). Summary of Unrealized Risk Management Positions As at December 31, Asset Liability Net Asset Liability 2017 Risk Management 2016 Risk Management 63 2 65 1,031 20 1,051 (968) (18) (986) 21 3 24 307 8 315 Net (286) (5) (291) The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried Crude Oil Interest Rate Total Fair Value at fair value: As at December 31, Level 2 – Prices Sourced From Observable Data or Market Corroboration 2017 (986) 2016 (291) Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities: As at December 31, Fair Value of Contracts, Beginning of Year Fair Value of Contracts Realized During the Year (1) Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year Unamortized Premium on Put Options Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts Fair Value of Contracts, End of Year 2017 (291) 200 (929) 16 18 (986) 2016 271 (211) (343) - (8) (291) (1) Includes a realized loss of $33 million (2016 – $58 million gain) related to the Conventional segment which is included in discontinued operations. Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset. The following table provides a summary of the Company’s offsetting risk management positions: As at December 31, Recognized Risk Management Positions 2017 Risk Management Liability Asset Net 2016 Risk Management Liability Asset Net Gross Amount Amount Offset 135 (70) 1,121 (986) (70) - 75 (51) 366 (51) (291) - Net Amount per Consolidated Financial Statements 65 1,051 (986) 24 315 (291) The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial. Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management receivables on a particular day. As at December 31, 2017, $26 million (2016 – $84 million) was pledged as collateral, of which $nil (2016 – $18 million) could have been withdrawn. C) Fair Value of Contingent Payment The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the future expected cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 3.3 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2017, the fair value of the contingent payment was estimated to be $206 million. As at December 31, 2017, average WCS forward pricing for the remaining term of the contingent payment is US$35.51 per barrel or C$44.55 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to value the contingent payment was 20 percent and seven percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows: WCS Forward Prices WTI Option Volatility U.S. to Canadian Dollar Foreign Exchange Rate Volatility Sensitivity Range Increase Decrease  $5.00 per bbl  five percent  five percent (167) (95) 2 111 85 (27) 2017 ANNUAL REPORT | 111 D) Earnings Impact of (Gains) Losses From Risk Management Positions Sensitivities For the years ended December 31, Realized (Gain) Loss (1) Unrealized (Gain) Loss (2) (Gain) Loss on Risk Management From Continuing Operations 2017 167 729 896 2016 (153) 554 401 2015 (447) 195 (252) (1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized risk management losses of $33 million in 2017 (2016 – $58 million gain; 2015 – $209 million gain) that were classified as discontinued operations. (2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment. 34. RISK MANAGEMENT Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk. To manage exposure to interest rate volatility, the Company entered into interest rate swap contracts related to expected future debt issuances. As at December 31, 2017, Cenovus had a notional amount of US$400 million in interest rate swaps. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. No foreign exchange contracts were outstanding at December 31, 2017. Net Fair Value of Risk Management Positions As at December 31, 2017 Notional Volumes Terms Average Price Crude Oil Contracts Fixed Price Contracts Brent Fixed Price WTI Fixed Price WTI Fixed Price Brent Put Options Brent Collars Brent Collars WTI Collars WCS Differential WCS Differential WCS Differential Other Financial Positions (1) Crude Oil Fair Value Position Interest Rate Swaps Total Fair Value 60,000 bbls/d 150,000 bbls/d 75,000 bbls/d 25,000 bbls/d January – June 2018 US$53.34/bbl January – June 2018 US$48.91/bbl July – December 2018 US$49.32/bbl January – June 2018 US$53.00/bbl 80,000 bbls/d January – June 2018 75,000 bbls/d July – December 2018 10,000 bbls/d January – June 2018 US$49.54 – US$59.86/bbl US$49.00 – US$59.69/bbl US$45.30 – US$62.77/bbl 16,300 bbls/d 14,800 bbls/d January – March 2018 US$(13.11)/bbl April – June 2018 US$(14.05)/bbl 10,500 bbls/d January – December 2018 US$(14.52)/bbl Fair Value Asset (Liability) (172) (384) (158) 1 (124) (110) (2) 14 7 25 (65) (968) (18) (986) (1) Other financial positions are part of ongoing operations to market the Company’s production. A) Commodity Price Risk Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes. Crude Oil – The Company has used fixed price swaps, put options and costless collars to partially mitigate its exposure to the commodity price risk on its crude oil sales. In addition, Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials. Condensate – The Company has used fixed price swaps to partially mitigate its exposure to the commodity price risk on its condensate purchases. Natural Gas – The Company may enter into transactions to partially mitigate its natural gas commodity price risk. To help protect against widening natural gas price differentials in various production areas, Cenovus may also enter into transactions to manage the price differentials between production areas and various sales points. 112 | CENOVUS ENERGY The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices and interest rates on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows: As at December 31, 2017 Sensitivity Range Increase Decrease Crude Oil Commodity Price  US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges Crude Oil Differential Price  US$2.50 per bbl Applied to Differential Hedges Tied to Production As at December 31, 2016 Sensitivity Range Increase Decrease (529) 11 (198) 1 507 (11) 193 (1) Crude Oil Commodity Price  US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges Crude Oil Differential Price  US$2.50 per bbl Applied to Differential Hedges Tied to Production B) Foreign Exchange Risk Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results. As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2017, Cenovus had US$7,650 million in U.S. dollar debt issued from Canada (2016 – US$4,750 million). In respect of these financial instruments, the impact of changes in the U.S. to Canadian dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows: For the years ended December 31, $0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate $0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate C) Interest Rate Risk Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. In addition, to manage exposure to interest rate volatility, the Company entered into interest rate swap contracts. As at December 31, 2017, Cenovus had a notional amount of US$400 million (2016 – US$400 million) in interest rate swaps. In respect of these financial instruments, the impact of changes in the interest rate would have resulted in a change to unrealized gains (losses) impacting earnings before income tax as 2017 2016 77 (77) 48 (48) 2017 2016 44 (50) 45 (52) follows: For the years ended December 31, 50 Basis Points Increase 50 Basis Points Decrease As at December 31, 2017, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $nil (2016 – $nil; 2015 – $nil). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates. D) Credit Risk Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee of the Board of Directors designed to ensure that its credit exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits. Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit policy tolerances. As at December 31, 2017 and 2016, substantially all of the Company’s accounts receivable were less than 60 days. As at December 31, 2017, 89 percent (2016 – 90 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties. As at December 31, 2017, Cenovus had three counterparties (2016 – three counterparties) whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net financial and physical contracts. The (Gain) Loss on Risk Management From Continuing Operations (1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized risk management losses of $33 million in 2017 (2016 – $58 million gain; 2015 – $209 million gain) that were classified as discontinued operations. (2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment. 2017 167 729 896 2016 (153) 554 401 2015 (447) 195 (252) For the years ended December 31, Realized (Gain) Loss (1) Unrealized (Gain) Loss (2) 34. RISK MANAGEMENT Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk. To manage exposure to interest rate volatility, the Company entered into interest rate swap contracts related to expected future debt issuances. As at December 31, 2017, Cenovus had a notional amount of US$400 million in interest rate swaps. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. No foreign exchange contracts were outstanding at December 31, 2017. Net Fair Value of Risk Management Positions As at December 31, 2017 Notional Volumes Terms Average Price (Liability) 60,000 bbls/d 150,000 bbls/d 75,000 bbls/d 25,000 bbls/d January – June 2018 US$53.34/bbl January – June 2018 US$48.91/bbl July – December 2018 US$49.32/bbl January – June 2018 US$53.00/bbl 80,000 bbls/d January – June 2018 75,000 bbls/d July – December 2018 10,000 bbls/d January – June 2018 US$49.54 – US$59.86/bbl US$49.00 – US$59.69/bbl US$45.30 – US$62.77/bbl 16,300 bbls/d 14,800 bbls/d January – March 2018 US$(13.11)/bbl April – June 2018 US$(14.05)/bbl 10,500 bbls/d January – December 2018 US$(14.52)/bbl Fair Value Asset (172) (384) (158) 1 (124) (110) (2) 14 7 25 (65) (968) (18) (986) Crude Oil Contracts Fixed Price Contracts Brent Fixed Price WTI Fixed Price WTI Fixed Price Brent Put Options Brent Collars Brent Collars WTI Collars WCS Differential WCS Differential WCS Differential Other Financial Positions (1) Crude Oil Fair Value Position Interest Rate Swaps Total Fair Value A) Commodity Price Risk D) Earnings Impact of (Gains) Losses From Risk Management Positions Sensitivities The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices and interest rates on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows: As at December 31, 2017 Sensitivity Range Increase Decrease Crude Oil Commodity Price Crude Oil Differential Price  US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges  US$2.50 per bbl Applied to Differential Hedges Tied to Production (529) 11 507 (11) As at December 31, 2016 Sensitivity Range Increase Decrease Crude Oil Commodity Price Crude Oil Differential Price  US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges  US$2.50 per bbl Applied to Differential Hedges Tied to Production (198) 1 193 (1) B) Foreign Exchange Risk Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results. As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2017, Cenovus had US$7,650 million in U.S. dollar debt issued from Canada (2016 – US$4,750 million). In respect of these financial instruments, the impact of changes in the U.S. to Canadian dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows: For the years ended December 31, $0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate $0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate C) Interest Rate Risk 2017 2016 77 (77) 48 (48) Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. In addition, to manage exposure to interest rate volatility, the Company entered into interest rate swap contracts. As at December 31, 2017, Cenovus had a notional amount of US$400 million (2016 – US$400 million) in interest rate swaps. In respect of these financial instruments, the impact of changes in the interest rate would have resulted in a change to unrealized gains (losses) impacting earnings before income tax as follows: For the years ended December 31, 50 Basis Points Increase 50 Basis Points Decrease 2017 2016 44 (50) 45 (52) As at December 31, 2017, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $nil (2016 – $nil; 2015 – $nil). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates. (1) Other financial positions are part of ongoing operations to market the Company’s production. D) Credit Risk Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes. Crude Oil – The Company has used fixed price swaps, put options and costless collars to partially mitigate its exposure to the commodity price risk on its crude oil sales. In addition, Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials. Condensate – The Company has used fixed price swaps to partially mitigate its exposure to the commodity price risk on its condensate purchases. Natural Gas – The Company may enter into transactions to partially mitigate its natural gas commodity price risk. To help protect against widening natural gas price differentials in various production areas, Cenovus may also enter into transactions to manage the price differentials between production areas and various sales points. Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee of the Board of Directors designed to ensure that its credit exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits. Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit policy tolerances. As at December 31, 2017 and 2016, substantially all of the Company’s accounts receivable were less than 60 days. As at December 31, 2017, 89 percent (2016 – 90 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties. As at December 31, 2017, Cenovus had three counterparties (2016 – three counterparties) whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net financial and physical contracts. The 2017 ANNUAL REPORT | 113 maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets, and long-term receivables is the total carrying value. The following table provides a reconciliation of cash flows arising from financing activities: E) Liquidity Risk Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 32, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt position. Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facility capacity and availability under its shelf prospectus. As at December 31, 2017, Cenovus had $610 million in cash and cash equivalents, and $4.5 billion available on its committed credit facility. In addition, Cenovus has unused capacity of US$4.6 billion under a base shelf prospectus, the availability of which is dependent on market conditions. Undiscounted cash outflows relating to financial liabilities are: As at December 31, 2017 Less than 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total Accounts Payable and Accrued Liabilities Risk Management Liabilities (1) Long-Term Debt (2) Other 2,635 1,031 494 - - 20 2,527 21 - - 1,429 11 - - 13,309 16 2,635 1,051 17,759 48 As at December 31, 2016 Less than 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total Accounts Payable and Accrued Liabilities Risk Management Liabilities (1) Long-Term Debt (2) Other 2,266 293 339 - (1) Risk management liabilities subject to master netting agreements. (2) Principal and interest, including current portion. - 22 2,662 25 - - 1,150 8 - - 7,550 16 2,266 315 11,701 49 35. SUPPLEMENTARY CASH FLOW INFORMATION For the years ended December 31, Interest Paid Interest Received Income Taxes Paid 2017 538 31 12 2016 350 32 11 2015 330 19 933 Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts recorded in the Consolidated Balance Sheets. As at December 31, 2017 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Unrealized Foreign Exchange (Gain) Loss (Note 7) (196) As at December 31, 2015 Changes From Financing Cash Flows: Dividends Paid Non-Cash Changes: Dividends Declared Amortization of Debt Discounts As at December 31, 2016 Changes From Financing Cash Flows: Issuance of Long-Term Debt Net Issuance (Repayment) of Revolving Long-Term Debt Issuance of Debt Under Asset Sale Bridge Facility (Repayment) of Debt Under Asset Sale Bridge Facility Common Shares Issued, Net of Issuance Costs Dividends Paid Non-Cash Changes: Common Shares Issued to ConocoPhillips Deferred Taxes on Share Issuance Costs Dividends Declared Unrealized Foreign Exchange (Gain) Loss Finance Costs Other As at December 31, 2017 36. COMMITMENTS AND CONTINGENCIES A) Commitments Current Portion of Dividends Long-Term Long-Term Payable Debt Debt 6,525 Share Capital 5,534 (166) 166 (225) 225 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 8 - - 6,332 5,534 3,842 32 2,677 892 (900) (2,700) (697) 28 (1) 9,513 11,040 - - 3 - - - - - - 122 - - - - 108 - - - - - - - - - - - - - 2,899 2,579 28 18 355 - 70 26 271 3 Fixed Price Product Sales - - - 1,179 1,073 1,093 1,292 1,388 15,687 21,712 As at December 31, 2016 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Transportation and Storage (1) Operating Leases (Building Leases) (2) Capital Commitments Other Long-Term Commitments Total Payments (3) Transportation and Storage (1) Operating Leases (Building Leases) (2) Product Purchases Capital Commitments Other Long-Term Commitments Total Payments (3) Fixed Price Product Sales 899 155 16 109 682 101 70 23 80 956 3 886 146 2 39 711 146 - 3 27 887 - 919 142 - 32 722 146 - - - 26 894 1,123 141 1,223 13,260 18,310 2,305 3,029 - 28 - - - 15 - 140 - 25 - - - 15 - 1,031 145 1,239 21,875 142 2,465 26,260 3,145 1,191 1,396 24,448 29,772 (1) Includes transportation commitments of $9 billion (2016 – $19 billion) that are subject to regulatory approval or have been approved, but are not yet in service. (2) (3) Excludes committed payment for which a provision has been provided. For 2017, contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. For 2016, contracts undertaken on behalf of FCCL and WRB are reflected at Cenovus’s 50 percent interest. 114 | CENOVUS ENERGY and long-term receivables is the total carrying value. E) Liquidity Risk Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 32, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt position. Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facility capacity and availability under its shelf prospectus. As at December 31, 2017, Cenovus had $610 million in cash and cash equivalents, and $4.5 billion available on its committed credit facility. In addition, Cenovus has unused capacity of US$4.6 billion under a base shelf prospectus, the availability of which is dependent on market conditions. Undiscounted cash outflows relating to financial liabilities are: As at December 31, 2017 Less than 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total As at December 31, 2016 Less than 1 Year Years 2 and 3 Years 4 and 5 Thereafter Total Accounts Payable and Accrued Liabilities Risk Management Liabilities (1) Long-Term Debt (2) Other Accounts Payable and Accrued Liabilities 2,266 Risk Management Liabilities (1) Long-Term Debt (2) Other (1) Risk management liabilities subject to master netting agreements. (2) Principal and interest, including current portion. 2,635 1,031 494 - 293 339 - - 20 21 2,527 - 22 25 2,662 - - 1,429 11 - - 8 1,150 13,309 16 - - - - 7,550 16 2,635 1,051 17,759 48 2,266 315 11,701 49 35. SUPPLEMENTARY CASH FLOW INFORMATION For the years ended December 31, Interest Paid Interest Received Income Taxes Paid 2017 538 31 12 2016 350 32 11 2015 330 19 933 maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets, The following table provides a reconciliation of cash flows arising from financing activities: Current Portion of Long-Term Debt Dividends Payable As at December 31, 2015 Changes From Financing Cash Flows: Dividends Paid Non-Cash Changes: Dividends Declared Unrealized Foreign Exchange (Gain) Loss (Note 7) Amortization of Debt Discounts As at December 31, 2016 Changes From Financing Cash Flows: Issuance of Long-Term Debt Net Issuance (Repayment) of Revolving Long-Term Debt Issuance of Debt Under Asset Sale Bridge Facility (Repayment) of Debt Under Asset Sale Bridge Facility Common Shares Issued, Net of Issuance Costs Dividends Paid Non-Cash Changes: Common Shares Issued to ConocoPhillips Deferred Taxes on Share Issuance Costs Dividends Declared Unrealized Foreign Exchange (Gain) Loss Finance Costs Other As at December 31, 2017 - (166) 166 - - - - - - - - (225) - - 225 - - - - Long-Term Debt Share Capital 6,525 5,534 - - (196) 3 - - - - 6,332 5,534 3,842 32 2,677 - - - - - (697) 28 (1) - - - - 2,899 - 2,579 28 - - - - 9,513 11,040 - - - - - - - - 892 - - - - - - 8 - - (900) (2,700) 36. COMMITMENTS AND CONTINGENCIES A) Commitments Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts recorded in the Consolidated Balance Sheets. As at December 31, 2017 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Transportation and Storage (1) Operating Leases (Building Leases) (2) Capital Commitments Other Long-Term Commitments Total Payments (3) 899 155 16 109 886 146 2 39 919 142 - 32 1,123 141 - 28 1,223 13,260 18,310 140 - 25 2,305 3,029 - 122 18 355 1,179 1,073 1,093 1,292 1,388 15,687 21,712 Fixed Price Product Sales - - - - - - - As at December 31, 2016 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total Transportation and Storage (1) Operating Leases (Building Leases) (2) Product Purchases Capital Commitments Other Long-Term Commitments Total Payments (3) Fixed Price Product Sales 682 101 70 23 80 956 3 711 146 - 3 27 887 - 722 146 - - 26 894 - 1,031 145 - - 15 1,239 21,875 142 2,465 26,260 3,145 - - 15 - - 108 70 26 271 1,191 1,396 24,448 29,772 - - - 3 (1) (2) (3) Includes transportation commitments of $9 billion (2016 – $19 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Excludes committed payment for which a provision has been provided. For 2017, contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. For 2016, contracts undertaken on behalf of FCCL and WRB are reflected at Cenovus’s 50 percent interest. 2017 ANNUAL REPORT | 115 Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement. As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for performance under certain contracts (2016 – $258 million). In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 34. B) Contingencies Legal Proceedings Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements. Decommissioning Liabilities Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of $1,029 million, based on current legislation and estimated costs, related to its upstream properties, refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in legislation and changes in costs. Income Tax Matters The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate. Contingent Payment In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. As at December 31, 2017, the estimated fair value of the contingent payment was $206 million (see Note 22). 116 | CENOVUS ENERGY SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics ($ millions, except per share amounts) Revenues Gross Sales Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Less: Royalties Revenues from Continuing Operations Conventional (Net of Royalties) - Discontinued Operations Total Revenues Operating Margin (1) Oil Sands Deep Basin Refining and Marketing Operating Margin from Continuing Operations Conventional - Discontinued Operations Total Operating Margin Adjusted Funds Flow (2) Total Cash From Operating Activities Deduct (Add Back): Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Total Adjusted Funds Flow Total Per Share - Basic and Diluted Earnings Operating Earnings (Loss) from Continuing Operations (3) Per Share from Continuing Operations - Diluted Total Operating Earnings (Loss) (3) Total Per Share - Diluted Net Earnings (Loss) from Continuing Operations Per Share from Continuing Operations - Basic and Diluted Total Net Earnings (Loss) Total Per Share - Basic and Diluted Net Capital Investment Oil Sands Foster Creek Christina Lake Other Oil Sands Total Oil Sands Deep Basin Refining and Marketing Corporate Capital Investment from Continuing Operations Conventional (Discontinued Operations) Total Capital Investment Acquisitions (4) Divestitures Net Acquisition and Divestiture Activity Net Capital Investment Year Q4 Q3 Q2 Q1 Year 2017 2016 Q2 Q1 Year Q2 Q1 Year 1,239 328 861 (25) 519 745 0.67 (31) 36 323 0.39 (91) (471) 1,423 1.71 2017 2016 Q2 Q1 Year 7,362 555 9,852 (455) 271 17,043 1,135 18,178 Year 2,187 207 2,394 598 2,992 491 3,483 Year 3,059 (107) 252 2,914 2.64 Year (34) (0.03) 126 0.11 2,268 2.06 3,366 3.05 455 426 92 973 225 180 77 1,455 206 1,661 18,388 (3,210) 15,178 16,839 2,424 231 2,690 (133) 133 5,079 189 5,268 Q4 612 92 704 314 1,018 70 1,088 Q4 900 (32) 66 866 0.70 Q4 (533) (0.43) (514) (0.42) (776) (0.63) 620 0.50 143 154 16 313 148 56 40 557 26 583 87 2,210 200 2,161 (118) 67 4,386 286 4,672 2017 Q3 822 64 886 211 1,097 117 1,214 2017 Q3 592 (19) (369) 980 0.80 Q3 240 0.20 327 0.27 275 0.22 (82) (0.07) Q3 122 132 19 273 64 38 21 396 42 438 70 1,666 124 2,397 (106) 44 4,037 336 4,373 501 51 552 20 572 159 731 298 0.27 352 0.32 2,558 2.30 2,617 2.35 120 77 18 215 13 40 9 277 50 327 18,231 - 18,231 18,558 1,062 - 2,604 (98) 27 3,541 324 3,865 252 - 252 53 305 145 450 (39) (0.05) (39) (0.05) 211 0.25 211 0.25 172 70 63 39 - 46 7 225 88 313 - - - 2,929 8,439 (353) - 9 11,006 1,128 12,134 2016 877 - 877 346 1,223 544 1,767 2016 (291) (0.35) (377) (0.45) (459) (0.55) (545) (0.65) 263 282 59 604 - 220 31 855 171 1,026 11 (8) 3 Year Q4 Q2 Q1 Year 2017 2016 (2,271) (2,184) (1,601) (939) (869) (431) Operating Margin 313 1,029 Free Funds Flow Before Dividends Free Funds Flow Free Funds Flow ) s n o i l l i m $ ( 1,000 900 800 700 600 500 400 300 200 100 0 ) s n o i l l i m $ ( 700 600 500 400 300 200 100 0 Q4 2017 Q4 2016 Adjusted Funds Flow (2) Capital Investment Oil Sands Deep Basin Refining & Marketing Q4 2017 Q4 2016 (1) (2) (3) (4) Operating Margin is an additional subtotal found in Note 1 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis. In connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3, which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the fair value was $11,605 million as at May 17, 2017. Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement. As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for performance under certain contracts (2016 – $258 million). In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 34. B) Contingencies Legal Proceedings Decommissioning Liabilities legislation and changes in costs. Income Tax Matters Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements. Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of $1,029 million, based on current legislation and estimated costs, related to its upstream properties, refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate. Contingent Payment (see Note 22). In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. As at December 31, 2017, the estimated fair value of the contingent payment was $206 million SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics ($ millions, except per share amounts) Revenues Gross Sales Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Less: Royalties Revenues from Continuing Operations Conventional (Net of Royalties) - Discontinued Operations Total Revenues Operating Margin (1) Oil Sands Deep Basin Refining and Marketing Operating Margin from Continuing Operations Conventional - Discontinued Operations Total Operating Margin Adjusted Funds Flow (2) Total Cash From Operating Activities Deduct (Add Back): Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Total Adjusted Funds Flow Total Per Share - Basic and Diluted Earnings Operating Earnings (Loss) from Continuing Operations (3) Per Share from Continuing Operations - Diluted Total Operating Earnings (Loss) (3) Total Per Share - Diluted Net Earnings (Loss) from Continuing Operations Per Share from Continuing Operations - Basic and Diluted Total Net Earnings (Loss) Total Per Share - Basic and Diluted Net Capital Investment Oil Sands Foster Creek Christina Lake Other Oil Sands Total Oil Sands Deep Basin Refining and Marketing Corporate Capital Investment from Continuing Operations Conventional (Discontinued Operations) Total Capital Investment Acquisitions (4) Divestitures Net Acquisition and Divestiture Activity Net Capital Investment Year Q4 Q3 Q2 Q1 Year 2017 2016 7,362 555 9,852 (455) 271 17,043 1,135 18,178 Year 2,187 207 2,394 598 2,992 491 3,483 Year 3,059 (107) 252 2,914 2.64 Year (34) (0.03) 126 0.11 2,268 2.06 3,366 3.05 2,424 231 2,690 (133) 133 5,079 189 5,268 Q4 612 92 704 314 1,018 70 1,088 Q4 900 (32) 66 866 0.70 Q4 (533) (0.43) (514) (0.42) (776) (0.63) 620 0.50 2,210 200 2,161 (118) 67 4,386 286 4,672 2017 Q3 822 64 886 211 1,097 117 1,214 2017 Q3 592 (19) (369) 980 0.80 1,666 124 2,397 (106) 44 4,037 336 4,373 1,062 - 2,604 (98) 27 3,541 324 3,865 2,929 - 8,439 (353) 9 11,006 1,128 12,134 2016 Q2 Q1 Year 501 51 552 20 572 159 731 252 - 252 53 305 145 450 877 - 877 346 1,223 544 1,767 2016 Q2 Q1 Year 1,239 328 861 (25) 519 745 0.67 (31) 36 323 0.39 (91) (471) 1,423 1.71 2017 2016 Q3 240 0.20 327 0.27 275 0.22 (82) (0.07) Q2 Q1 Year 298 0.27 352 0.32 2,558 2.30 2,617 2.35 (39) (0.05) (39) (0.05) 211 0.25 211 0.25 (291) (0.35) (377) (0.45) (459) (0.55) (545) (0.65) Year Q4 Q3 Q2 Q1 Year 2017 2016 455 426 92 973 225 180 77 1,455 206 1,661 18,388 (3,210) 15,178 16,839 143 154 16 313 148 56 40 557 26 583 87 (2,271) (2,184) (1,601) 122 132 19 273 64 38 21 396 42 438 70 (939) (869) (431) 120 77 18 215 13 40 9 277 50 327 18,231 - 18,231 18,558 70 63 39 172 - 46 7 225 88 313 - - - 313 263 282 59 604 - 220 31 855 171 1,026 11 (8) 3 1,029 Free Funds Flow Before Dividends Operating Margin ) s n o i l l i m $ ( 1,000 900 800 700 600 500 400 300 200 100 0 Free Funds Flow Free Funds Flow Q4 2017 Q4 2016 Adjusted Funds Flow (2) Capital Investment ) s n o i l l i m $ ( 700 600 500 400 300 200 100 0 Oil Sands Deep Basin Refining & Marketing Q4 2017 Q4 2016 (1) (2) (3) (4) Operating Margin is an additional subtotal found in Note 1 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis. In connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3, which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the fair value was $11,605 million as at May 17, 2017. 2017 ANNUAL REPORT | 117 SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics (continued) Financial Metrics (Non-GAAP Measures) Net Debt to Adjusted EBITDA (1) (2) Return on Capital Employed (3) Return on Common Equity (4) Income Tax & Exchange Rates Effective Tax Rates Using: Net Earnings From Continuing Operations Operating Earnings From Continuing Operations, Excluding Divestitures Foreign Exchange Rates (US$ per C$1) Average Period End Common Share Information Common Shares Outstanding (millions) Period End Average - Basic and Diluted Dividends ($ per share) Closing Price - TSX (C$ per share) Closing Price - NYSE (US$ per share) Share Volume Traded (millions) Operating Statistics - Before Royalties Upstream Production Volumes Crude Oil and Natural Gas Liquids (bbls/d) Oil Sands Foster Creek Christina Lake Deep Basin Light and Medium Oil Natural Gas Liquids (5) Total Liquids Production from Continuing Operations Natural Gas (MMcf/d) Oil Sands Deep Basin Total Natural Gas Production from Continuing Operations Total Production from Continuing Operations (6) (BOE per day) Conventional Heavy Oil Light and Medium Oil Natural Gas Liquids (5) Natural Gas Total Production from Discontinued Operations (6) (BOE per day) Total Production (6) (BOE/d) Year 2.8x 16% 21% Q4 2.8x 16% 21% 2017 Q3 4.2x 13% 18% 2017 2016 Q2 Q1 Year 6.3x 12% 17% 1.6x 0% (2)% 1.9x (2)% (5)% 2016 Year Q4 Q3 Q2 Q1 Year (2.3)% 86.9% 42.8% 33.6% 0.771 0.797 0.787 0.797 0.798 0.801 0.744 0.771 0.756 0.751 0.755 0.745 2017 2016 Year Q4 Q3 Q2 Q1 Year Differential NYMEX - AECO (US$/Mcf) 1,228.8 1,102.5 0.20 11.48 9.13 2,908.3 1,228.8 1,228.8 0.05 11.48 9.13 703.3 1,228.8 1,228.8 0.05 12.51 10.02 804.1 1,228.8 1,113.3 0.05 9.56 7.37 907.7 833.3 833.3 0.05 15.05 11.30 493.2 833.3 833.3 0.20 20.30 15.13 1,491.7 Year Q4 Q3 Q2 Q1 Year 2017 2016 124,752 167,727 292,479 3,922 16,928 20,850 313,329 154,784 206,579 361,363 6,042 27,105 33,147 394,510 10 316 326 367,635 7 509 516 480,497 21,478 24,824 1,073 47,375 333 102,855 6,675 20,059 913 27,647 279 74,109 154,363 208,131 362,494 6,494 26,370 32,864 395,358 6 495 501 478,817 25,549 26,947 1,201 53,697 350 107,859 153,953 261,812 3,059 13,835 16,894 278,706 12 253 265 322,792 26,593 27,233 1,132 54,958 355 80,866 100,635 181,501 - - - 181,501 15 - 15 184,001 27,277 25,089 1,047 53,413 348 112,034 114,137 111,413 70,244 79,449 149,693 - - - 149,693 17 - 17 152,527 29,185 25,915 1,065 56,165 377 118,998 470,490 554,606 590,851 436,929 295,414 271,525 Benchmark Prices Production from Continuing Operations ) l b b / $ S U ( 70 60 50 40 30 20 10 0 Brent Condensate WTI WCS ) d / s l b b ( 400,000 350,000 300,000 250,000 200,000 150,000 100,000 50,000 0 ) d / f c M M ( 2,500 2,000 1,500 1,000 500 0 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Crude Oil NGLs Natural Gas Q4 2017 Q4 2016 Net debt includes the Company's short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, revaluation gain, remeasurement gains (losses) on contingent consideration, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve-month basis. Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders' equity plus average debt. month WTI based crude oil feedstock prices and on a last in, first out accounting basis (“LIFO”). Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders' equity. (1) (2) (3) (4) (5) Natural gas liquids include condensate volumes. (6) Natural gas volumes have been converted to barrels of oil equivalent ("BOE") on the basis of six thousand cubic feet ("Mcf") to one barrel ("bbl"). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. 118 | CENOVUS ENERGY (Excluding Realized Gain (Loss) on Risk Management) Year Q4 Q3 Q2 Q1 Year 2017 2016 19.52 20.19 17.61 21.94 (Excluding Realized Gain (Loss) on Risk Management) Year Q4 Q3 Q2 Q1 Year 2017 2016 36.86 39.29 34.58 36.31 37.77 27.37 1.76 5.73 9.03 - 0.17 6.51 8.94 - 20.89 22.38 20.01 19.90 21.25 11.75 (1) (2) (3) The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual Management's Discussion and Analysis. Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties (continued) Selected Average Benchmark Prices Crude Oil Prices (US$/bbl) Brent West Texas Intermediate ("WTI") Differential Brent - WTI Western Canadian Select ("WCS") WCS (C$) Mixed Sweet Blend (US$ ) Differential WTI - WCS Condensate (C5 @ Edmonton) Differential WTI - Condensate (Premium)/Discount Refining Margins 3-2-1 Crack Spreads (1) (US$/bbl) Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management) Chicago Group 3 Natural Gas Prices AECO (C$/Mcf) NYMEX (US$/Mcf) Oil Sands Foster Creek Christina Lake Deep Basin Crude Oil Natural Gas Liquids Natural Gas Conventional Oil Pelican Lake Weyburn Other Natural Gas Liquids Natural Gas Transportation and Blending Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Heavy Oil - Christina Lake ($/bbl) Transportation and Blending Total Heavy Oil - Oil Sands ($/bbl) Transportation and Blending Deep Basin Netbacks (2) Total Deep Basin (3) ($/BOE) Sales Price Royalties Operating Netback Transportation and Blending Production and Mineral Taxes Continuing Operations Netbacks (2) Total Continuing Operations (3) ($/BOE) Sales Price Royalties Operating Netback Transportation and Blending Production and Mineral Taxes Year Q4 Q3 Q2 Q1 Year 2017 2016 54.82 50.95 3.87 38.97 50.56 48.49 11.98 51.57 61.54 55.40 6.14 43.14 54.84 54.26 12.26 57.97 50.92 48.29 2.63 37.16 49.95 46.03 11.13 48.44 54.66 51.91 2.75 37.33 49.38 48.37 14.58 52.26 (0.62) (2.57) (0.15) (0.35) 16.77 16.61 21.09 18.77 14.78 14.27 11.54 13.18 2.43 3.11 1.26 1.96 2.93 1.40 2.77 3.18 1.13 2.94 3.32 1.10 Year Q4 Q3 Q2 Q1 Year 2017 2016 11.4% 2.5% 17.5% 3.1% 9.1% 1.6% 7.3% 2.6% 8.5% 2.7% 0.0% 1.6% 45.04 43.32 1.72 29.48 39.05 40.11 13.84 42.47 0.85 13.07 12.27 2.09 2.46 0.89 - - - 12.5% 23.6% 12.8% 13.5% 4.6% 30.32 (0.01) 8.84 10.55 10.94 25.30 0.33 4.68 7.48 12.81 27.64 0.17 6.62 8.91 11.94 - - - - - - 52.18 48.21 3.97 38.27 47.96 45.32 9.94 47.61 0.60 19.66 20.20 2.04 3.00 1.39 14.5% 10.0% 3.5% 19.6% 24.8% 13.8% 12.2% 5.1% 41.57 2.98 8.68 9.53 20.38 38.84 0.55 4.14 6.08 28.07 40.02 1.60 6.11 7.58 24.73 1.28 1.96 9.00 0.03 5.34 1.52 5.10 7.94 0.01 - - - 19.8% 28.3% 12.4% 13.3% 4.8% 40.62 2.83 7.72 9.99 20.08 35.86 0.86 4.13 8.08 22.79 38.08 1.78 5.81 8.97 21.52 - - - - - - 17.4% 9.2% 4.1% 17.4% 25.8% 12.7% 13.0% 5.2% 44.38 2.49 10.44 12.31 19.14 36.54 0.85 4.10 7.04 24.55 39.73 1.52 6.68 9.19 22.34 1.45 1.96 8.84 0.03 9.66 1.50 5.78 9.13 - 15.0% 10.8% 4.4% 14.8% 12.2% 5.6% 19.2% 26.9% 12.3% 12.9% 4.8% - 28.8% 9.7% 13.0% 3.6% 43.75 4.00 8.73 10.46 20.56 0.87 4.52 6.84 2.22 6.33 8.40 39.78 45.13 27.55 31.55 41.49 46.08 24.54 27.51 47.37 6.86 8.07 10.37 22.07 1.23 5.42 6.93 3.63 6.55 8.39 1.54 2.08 8.56 0.02 7.32 2.07 5.43 8.46 0.01 1.84 2.26 7.99 0.02 8.08 3.16 5.42 8.32 0.01 Oil Sands Netbacks (2) Heavy Oil - Foster Creek ($/bbl) (Excluding Realized Gain (Loss) on Risk Management) Year Q4 Q3 Q2 Q1 Year 2017 2016 Operating Earnings From Continuing Operations, Excluding Divestitures (2.3)% 86.9% SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics (continued) Financial Metrics (Non-GAAP Measures) Net Debt to Adjusted EBITDA (1) (2) Return on Capital Employed (3) Return on Common Equity (4) Income Tax & Exchange Rates Effective Tax Rates Using: Net Earnings From Continuing Operations Foreign Exchange Rates (US$ per C$1) Average Period End Common Share Information Common Shares Outstanding (millions) Period End Average - Basic and Diluted Dividends ($ per share) Closing Price - TSX (C$ per share) Closing Price - NYSE (US$ per share) Share Volume Traded (millions) Operating Statistics - Before Royalties Upstream Production Volumes Crude Oil and Natural Gas Liquids (bbls/d) Oil Sands Foster Creek Christina Lake Deep Basin Light and Medium Oil Natural Gas Liquids (5) Natural Gas (MMcf/d) Oil Sands Deep Basin Conventional Heavy Oil Light and Medium Oil Natural Gas Liquids (5) Natural Gas Total Natural Gas Production from Continuing Operations Total Production from Continuing Operations (6) (BOE per day) Total Production from Discontinued Operations (6) (BOE per day) Total Production (6) (BOE/d) 2017 Q3 4.2x 13% 18% 2017 2017 1,228.8 1,228.8 0.05 12.51 10.02 804.1 Year 2.8x 16% 21% Q4 2.8x 16% 21% 2016 Q2 Q1 Year 6.3x 12% 17% 1.6x 0% (2)% 1.9x (2)% (5)% Year Q4 Q3 Q2 Q1 Year 0.771 0.797 0.787 0.797 0.798 0.801 0.744 0.771 0.756 0.751 0.755 0.745 Year Q4 Q3 Q2 Q1 Year 1,228.8 1,102.5 0.20 11.48 9.13 2,908.3 1,228.8 1,228.8 0.05 11.48 9.13 703.3 1,228.8 1,113.3 0.05 9.56 7.37 907.7 833.3 833.3 0.05 15.05 11.30 493.2 Year Q4 Q3 Q2 Q1 Year 2017 2016 124,752 167,727 292,479 154,784 206,579 361,363 3,922 16,928 20,850 6,042 27,105 33,147 154,363 208,131 362,494 6,494 26,370 32,864 107,859 153,953 261,812 3,059 13,835 16,894 80,866 100,635 181,501 70,244 79,449 149,693 - - - 15 - 15 - - - 17 - 17 10 316 326 7 509 516 6 495 501 12 253 265 367,635 480,497 478,817 322,792 184,001 152,527 21,478 24,824 1,073 47,375 333 6,675 20,059 913 27,647 279 25,549 26,947 1,201 53,697 350 26,593 27,233 1,132 54,958 355 27,277 25,089 1,047 53,413 348 102,855 74,109 112,034 114,137 111,413 29,185 25,915 1,065 56,165 377 118,998 470,490 554,606 590,851 436,929 295,414 271,525 2016 42.8% 33.6% 2016 833.3 833.3 0.20 20.30 15.13 1,491.7 ) d / f c M M ( 2,500 2,000 1,500 1,000 500 0 Benchmark Prices Production from Continuing Operations Brent Condensate WTI WCS ) d / s l b b ( 400,000 350,000 300,000 250,000 200,000 150,000 100,000 50,000 0 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Crude Oil NGLs Natural Gas Q4 2017 Q4 2016 Net debt includes the Company's short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, revaluation gain, remeasurement gains (losses) on contingent consideration, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve-month basis. Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders' equity plus average debt. Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders' equity. (5) Natural gas liquids include condensate volumes. (6) Natural gas volumes have been converted to barrels of oil equivalent ("BOE") on the basis of six thousand cubic feet ("Mcf") to one barrel ("bbl"). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of ) l b b / $ S U ( 70 60 50 40 30 20 10 0 (1) (2) (3) (4) value. SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties (continued) Selected Average Benchmark Prices Crude Oil Prices (US$/bbl) Brent West Texas Intermediate ("WTI") Differential Brent - WTI Western Canadian Select ("WCS") WCS (C$) Mixed Sweet Blend (US$ ) Differential WTI - WCS Condensate (C5 @ Edmonton) Differential WTI - Condensate (Premium)/Discount Refining Margins 3-2-1 Crack Spreads (1) (US$/bbl) Chicago Group 3 Natural Gas Prices AECO (C$/Mcf) NYMEX (US$/Mcf) Differential NYMEX - AECO (US$/Mcf) Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management) Oil Sands Foster Creek Christina Lake Deep Basin Crude Oil Natural Gas Liquids Natural Gas Conventional Oil Pelican Lake Weyburn Other Natural Gas Liquids Natural Gas Total Liquids Production from Continuing Operations 313,329 394,510 395,358 278,706 181,501 149,693 Oil Sands Netbacks (2) Heavy Oil - Foster Creek ($/bbl) (Excluding Realized Gain (Loss) on Risk Management) Sales Price Royalties Transportation and Blending Operating Netback Heavy Oil - Christina Lake ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Total Heavy Oil - Oil Sands ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Deep Basin Netbacks (2) Total Deep Basin (3) ($/BOE) (Excluding Realized Gain (Loss) on Risk Management) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Continuing Operations Netbacks (2) Total Continuing Operations (3) ($/BOE) (Excluding Realized Gain (Loss) on Risk Management) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Year Q4 Q3 Q2 Q1 Year 2017 2016 54.82 50.95 3.87 38.97 50.56 48.49 11.98 51.57 (0.62) 61.54 55.40 6.14 43.14 54.84 54.26 12.26 57.97 (2.57) 16.77 16.61 21.09 18.77 2.43 3.11 1.26 1.96 2.93 1.40 52.18 48.21 3.97 38.27 47.96 45.32 9.94 47.61 0.60 19.66 20.20 2.04 3.00 1.39 50.92 48.29 2.63 37.16 49.95 46.03 11.13 48.44 (0.15) 54.66 51.91 2.75 37.33 49.38 48.37 14.58 52.26 (0.35) 14.78 14.27 11.54 13.18 2.77 3.18 1.13 2.94 3.32 1.10 45.04 43.32 1.72 29.48 39.05 40.11 13.84 42.47 0.85 13.07 12.27 2.09 2.46 0.89 Year Q4 Q3 Q2 Q1 Year 2017 2016 11.4% 2.5% 17.5% 3.1% 9.1% 1.6% 7.3% 2.6% 8.5% 2.7% 0.0% 1.6% 15.0% 10.8% 4.4% 14.8% 12.2% 5.6% 19.2% 26.9% 12.3% 12.9% 4.8% - 28.8% 9.7% 13.0% 3.6% 14.5% 10.0% 3.5% 19.6% 24.8% 13.8% 12.2% 5.1% 17.4% 9.2% 4.1% 17.4% 25.8% 12.7% 13.0% 5.2% - - - 19.8% 28.3% 12.4% 13.3% 4.8% - - - 12.5% 23.6% 12.8% 13.5% 4.6% Year Q4 Q3 Q2 Q1 Year 2017 2016 43.75 4.00 8.73 10.46 20.56 39.78 0.87 4.52 6.84 27.55 41.49 2.22 6.33 8.40 24.54 47.37 6.86 8.07 10.37 22.07 45.13 1.23 5.42 6.93 31.55 46.08 3.63 6.55 8.39 27.51 41.57 2.98 8.68 9.53 20.38 38.84 0.55 4.14 6.08 28.07 40.02 1.60 6.11 7.58 24.73 44.38 2.49 10.44 12.31 19.14 36.54 0.85 4.10 7.04 24.55 39.73 1.52 6.68 9.19 22.34 40.62 2.83 7.72 9.99 20.08 35.86 0.86 4.13 8.08 22.79 38.08 1.78 5.81 8.97 21.52 30.32 (0.01) 8.84 10.55 10.94 25.30 0.33 4.68 7.48 12.81 27.64 0.17 6.62 8.91 11.94 Year Q4 Q3 Q2 Q1 Year 2017 2016 19.52 1.54 2.08 8.56 0.02 7.32 20.19 1.84 2.26 7.99 0.02 8.08 17.61 1.28 1.96 9.00 0.03 5.34 21.94 1.45 1.96 8.84 0.03 9.66 - - - - - - - - - - - - Year Q4 Q3 Q2 Q1 Year 2017 2016 36.86 2.07 5.43 8.46 0.01 20.89 39.29 3.16 5.42 8.32 0.01 22.38 34.58 1.52 5.10 7.94 0.01 20.01 36.31 1.50 5.78 9.13 - 19.90 37.77 1.76 5.73 9.03 - 21.25 27.37 0.17 6.51 8.94 - 11.75 (1) (2) (3) The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based crude oil feedstock prices and on a last in, first out accounting basis (“LIFO”). Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual Management's Discussion and Analysis. Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. 2017 ANNUAL REPORT | 119 SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties (continued) Conventional (Discontinued Operations) Netbacks Heavy Oil - Conventional ($/bbl) (1) (Excluding Realized Gain (Loss) on Risk Management) Year Q4 Q3 Q2 Q1 Year 2017 2016 Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Light and Medium Oil ($/bbl) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Natural Gas Liquids ($/bbl) Sales Price Royalties Netback Natural Gas ($/Mcf) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Total Conventional (2) ($/BOE) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Consolidated Netbacks Total Consolidated (2) ($/BOE) (1) (Excluding Realized Gain (Loss) on Risk Management) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Realized Gain (Loss) on Risk Management Total Crude Oil ($/bbl) Total Production (2) ($/BOE) Refinery Operations (3) Crude Oil Capacity (Mbbls/d) Crude Oil Runs (Mbbls/d) Heavy Oil Light/Medium Crude Utilization Refined Products (Mbbls/d) 48.46 6.41 4.44 14.85 0.02 22.74 56.19 11.96 2.76 17.03 1.87 22.57 44.36 5.71 38.65 2.47 0.12 0.10 1.25 0.01 0.99 32.10 4.65 1.93 11.25 0.49 13.78 58.93 3.10 4.49 20.64 0.05 30.65 61.24 13.99 2.64 18.47 2.29 23.85 52.16 6.77 45.39 2.05 0.08 0.09 1.37 - 0.51 30.08 4.27 1.48 12.02 0.60 11.71 48.01 7.04 5.45 15.50 0.01 20.01 51.91 10.22 2.85 17.19 1.54 20.11 38.12 4.66 33.46 1.94 0.10 0.11 1.19 0.01 0.53 29.94 4.45 2.26 11.38 0.42 11.43 46.67 6.15 4.48 14.56 0.01 21.47 56.40 11.58 2.82 16.08 1.85 24.07 41.06 5.32 35.74 2.80 0.14 0.08 1.15 0.01 1.42 33.53 4.69 2.00 10.85 0.47 15.52 47.77 7.03 3.40 12.86 0.02 24.46 56.84 12.75 2.70 16.77 1.95 22.67 48.35 6.42 41.93 3.00 0.14 0.13 1.31 0.02 1.40 34.19 5.07 1.82 10.99 0.51 15.80 35.82 3.31 4.60 13.38 0.01 14.52 46.48 9.28 2.73 15.65 1.24 17.58 31.16 4.21 26.95 2.33 0.10 0.11 1.12 - 1.00 26.54 3.18 2.08 10.23 0.27 10.78 Year Q4 Q3 Q2 Q1 Year 2017 2016 35.80 2.64 4.65 9.08 0.11 19.32 38.01 3.31 4.87 8.84 0.09 20.90 Year (2.83) (2.02) Q4 (7.38) (5.09) Year 460 442 202 240 96% 470 Q4 460 450 195 255 98% 480 33.71 2.08 4.56 8.59 0.08 18.40 2017 Q3 (0.37) (0.24) 2017 Q3 460 462 213 249 100% 490 35.58 2.34 4.78 9.59 0.13 18.74 36.37 3.06 4.20 9.80 0.20 19.11 27.01 1.49 4.56 9.51 0.12 11.33 2016 Q2 Q1 Year 0.39 0.28 (4.55) (3.56) 3.24 2.44 2016 Q2 Q1 Year 460 449 201 248 98% 476 460 406 200 206 88% 433 460 444 233 211 97% 471 (1) (2) Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual Management's Discussion and Analysis. Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. (3) Represents 100% of the Wood River and Borger refinery operations. 120 | CENOVUS ENERGY SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties (continued) 2017 2016 Oil and Gas Information ADVISORY Conventional (Discontinued Operations) Netbacks (Excluding Realized Gain (Loss) on Risk Management) (1) Year Q4 Q3 Q2 Q1 Year Heavy Oil - Conventional ($/bbl) Transportation and Blending Production and Mineral Taxes Light and Medium Oil ($/bbl) Transportation and Blending Production and Mineral Taxes Natural Gas Liquids ($/bbl) Natural Gas ($/Mcf) Transportation and Blending Production and Mineral Taxes Total Conventional (2) ($/BOE) Transportation and Blending Production and Mineral Taxes Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Consolidated Netbacks Total Consolidated (2) ($/BOE) (1) Sales Price Royalties Operating Netback Transportation and Blending Production and Mineral Taxes Refinery Operations (3) Crude Oil Capacity (Mbbls/d) Crude Oil Runs (Mbbls/d) Heavy Oil Light/Medium Crude Utilization Refined Products (Mbbls/d) Realized Gain (Loss) on Risk Management Total Crude Oil ($/bbl) Total Production (2) ($/BOE) 48.46 6.41 4.44 14.85 0.02 22.74 56.19 11.96 2.76 17.03 1.87 22.57 44.36 5.71 38.65 2.47 0.12 0.10 1.25 0.01 0.99 32.10 4.65 1.93 11.25 0.49 13.78 58.93 3.10 4.49 20.64 0.05 30.65 61.24 13.99 2.64 18.47 2.29 23.85 52.16 6.77 45.39 2.05 0.08 0.09 1.37 - 0.51 30.08 4.27 1.48 12.02 0.60 11.71 46.67 6.15 4.48 14.56 0.01 21.47 56.40 11.58 2.82 16.08 1.85 24.07 41.06 5.32 35.74 2.80 0.14 0.08 1.15 0.01 1.42 33.53 4.69 2.00 10.85 0.47 15.52 47.77 7.03 3.40 12.86 0.02 24.46 56.84 12.75 2.70 16.77 1.95 22.67 48.35 6.42 41.93 3.00 0.14 0.13 1.31 0.02 1.40 34.19 5.07 1.82 10.99 0.51 15.80 35.80 38.01 33.71 35.58 36.37 27.01 2.64 4.65 9.08 0.11 3.31 4.87 8.84 0.09 2.08 4.56 8.59 0.08 2.34 4.78 9.59 0.13 3.06 4.20 9.80 0.20 1.49 4.56 9.51 0.12 19.32 20.90 18.40 18.74 19.11 11.33 Year (2.83) (2.02) Q4 (7.38) (5.09) Q2 Q1 Year 0.39 0.28 (4.55) (3.56) 3.24 2.44 Year 460 442 202 240 96% 470 Q4 460 450 195 255 98% 480 Q2 Q1 Year 460 449 201 248 98% 476 460 406 200 206 88% 433 460 444 233 211 97% 471 48.01 7.04 5.45 15.50 0.01 20.01 51.91 10.22 2.85 17.19 1.54 20.11 38.12 4.66 33.46 1.94 0.10 0.11 1.19 0.01 0.53 29.94 4.45 2.26 11.38 0.42 11.43 2017 Q3 (0.37) (0.24) 2017 Q3 460 462 213 249 100% 490 35.82 3.31 4.60 13.38 0.01 14.52 46.48 9.28 2.73 15.65 1.24 17.58 31.16 4.21 26.95 2.33 0.10 0.11 1.12 - 1.00 26.54 3.18 2.08 10.23 0.27 10.78 2016 2016 (Excluding Realized Gain (Loss) on Risk Management) Year Q4 Q3 Q2 Q1 Year 2017 2016 (1) (2) Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual Management's Discussion and Analysis. Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. (3) Represents 100% of the Wood River and Borger refinery operations. The estimates of reserves were prepared effective December 31, 2017 by independent qualified reserves evaluators, based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. Estimates are presented using an average of three IQRE’s January 1, 2018 price forecast. For additional information about our reserves and other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended December 31, 2017. Barrels of Oil Equivalent – natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. Forward-looking Information This Annual Report contains certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking information”) within the meaning of applicable securities legislation, including the U.S. Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although we believe that the expectations represented by such forward looking information are reasonable, there can be no assurance that such expectations will prove to be correct. Forward-looking information in this document is identified by words such as “anticipate”, “believe”, “expect”, “estimate”, “plan”, “forecast”, “future”, “target”, “position”, “project”, “committed”, “can be”, “pursue”, “capacity”, “could”, “should”, “will”, “focus”, “outlook”, “potential”, “priority”, “may”, “strategy”, “forward”, or similar expressions and includes suggestions of future outcomes, including statements about: our strategy and related milestones and schedules, including expected timing for oil sands expansion phases and associated expected production capacities; projections for 2018 and future years and our plans and strategies to realize such projections; forecast exchange rates and trends; our future opportunities for oil development; forecast operating and financial results, including forecast sales prices, costs and cash flows; targets for our Net Debt to Capitalization and Net Debt to Adjusted EBITDA ratios; our ability to satisfy payment obligations as they become due; priorities for our capital investment decisions; planned capital expenditures, including the amount, timing and financing thereof; expected future production, including the timing, stability or growth thereof; expected reserves; capacities, including for projects, transportation and refining; our ability to preserve our financial resilience and various plans and strategies with respect thereto; forecast cost savings and sustainability thereof; our priorities for 2018; future impact of regulatory measures; forecast commodity prices, differentials and trends and expected impact to Cenovus; potential impacts to Cenovus of various risks, including those related to commodity prices and the Acquisition; the potential effectiveness of our risk management strategies; new accounting standards, the timing for the adoption thereof by Cenovus, and anticipated impact on the Consolidated Financial Statements; expected impacts of the Acquisition; the availability and repayment of our credit facilities; potential asset sales and anticipated use of sales proceeds; expected impacts of the contingent payment related to the Acquisition; future use and development of technology; our ability to access and implement all technology necessary to efficientl and effectively operate our assets and achieve expected future cost reductions; and projected growth and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include: forecast oil and natural gas, natural gas liquids, condensate and refined products prices and other assumptions inherent in Cenovus’s 2018 guidance, available at cenovus.com; our projected capital investment levels, the flexibili y of our capital spending plans and the associated source of funding; the achievement of further cost reductions and sustainability thereof; expected condensate prices; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classifie as proved; future use and development of technology; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; achievement of expected impacts of the Acquisition; successful integration of the Deep Basin Assets; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficien manner; our ability to access sufficient capital to pursue our development plans; our ability to complete asset sales, including with desired transaction metrics and the timelines we expect; forecast bitumen, crude oil, natural gas liquids, condensate and refined products prices, forecast inflation and other assumptions inherent in our current guidance set out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized Western Canadian Select (“WCS”) prices and WCS prices used to calculate the contingent payment to ConocoPhillips; our projected capital investment levels, the flexibili y of capital spending plans and the associated sources of funding; sustainability 2017 ANNUAL REPORT | 121 of achieved cost reductions, achievement of further cost reductions and sustainability thereof; our ability to access and implement all technology necessary to achieve expected future results; our ability to implement capital projects or stages thereof in a successful and timely manner; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. 2018 guidance, as updated December 13, 2017, assumes: Brent prices of US$55.00/bbl, WTI prices of US$52.00/ bbl; WCS of US$37.00/bbl; NYMEX natural gas prices of US$3.00/MMBtu; AECO natural gas prices of $2.20/GJ; Chicago 3-2-1 crack spread of US$15.00/bbl; and an exchange rate of $0.78 US$/C$. The risk factors and uncertainties that could cause our actual results to differ materially, include: possible failure by us to realize the anticipated benefits of and synergies from the Acquisition; possible failure to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; the effectiveness of our risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates; commodity prices, currency and interest rates; possible lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; changes to our dividend plans or strategy, including the dividend reinvestment plan; accuracy of our reserves, future production and future net revenue estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationship with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflation ry pressures on operating costs, including labour, materials, natural gas and other energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and its application to our business; risks associated with climate change; the timing and the costs of well and pipeline construction; our ability to secure adequate and cost-effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; changes in labour relationships; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our Consolidated Financial Statements; changes in general economic, market and business conditions; the political and economic conditions in the countries in which we operate or supply; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us. Statements relating to “reserves” are deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward looking information. For a full discussion of our material risk factors, see “Risk Management and Risk Factors” in our Annual MD&A for the period ended December 31, 2017, available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. 122 | CENOVUS ENERGY ABBREVIATIONS The following abbreviations have been used in this document: Crude Oil bbl Mbbls/d MMbbls BOE MMBOE WTI WCS CDB MSW Barrel thousand barrels per day million barrels barrel of oil equivalent million barrel of oil equivalent West Texas Intermediate Western Canadian Select Christina Dilbit Blend Mixed Sweet Blend NETBACK RECONCILIATIONS Consolidated Financial Statements. Total Production From Continuing Operations Continuing Upstream Financial Results Natural Gas Mcf MMcf Bcf GJ AECO NYMEX thousand cubic feet million cubic feet billion cubic feet MMBtu million British thermal units gigajoule Alberta Energy Company New York Mercantile Exchange The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Year Ended December 31, 2017 ($ millions) Oil Sands (1) Deep Basin (1) Condensate Inventory Other Continuing Operations Per Consolidated Financial Statements Adjustments Year Ended December 31, 2016 ($ millions) Oil Sands (1) Deep Basin (1) Condensate Inventory Other Continuing Operations Per Consolidated Financial Statements Adjustments (1,402) (2) 1,525 (1,402) 44 Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Year Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin 3,030 29 1,815 531 - 655 (404) 1,059 Three Months Ended December 31, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin 7,362 230 3,704 934 - 2,494 307 2,187 2,929 1,721 501 9 - 698 (179) 877 - - - - - - - - 2,424 113 1,193 271 - 847 235 612 555 41 56 250 207 1 - 207 - - - - - - - - 61 1 1 3 1 55 - 55 231 20 24 94 1 92 - 92 7,917 271 3,760 1,184 1 2,701 307 2,394 2,929 1,721 501 9 - 698 (179) 877 3,091 30 1,816 534 1 710 (404) 1,114 2,655 133 1,217 365 1 939 235 704 (3,050) (3,050) - - - - - - - - - - - - - - - - - - - - - - - - (990) (990) - - - - - - - - - - - - - - - - - - (44) (44) 38 38 (1) - - - - 1 - 1 December 31, 2015 ($ millions) Oil Sands (1) Deep Basin (1) Conventional (2) Condensate Inventory Other Continuing Operations Per Consolidated Financial Statements Adjustments (1,441) (1,441) (38) Per Interim Consolidated Financial Statements Adjustments Oil Sands (3) Deep Basin (3) Condensate Inventory Other Continuing Operations Basis of Netback Calculation Continuing Operations 4,822 271 709 1,107 1 2,734 307 2,427 Basis of Netback Calculation Continuing Operations Basis of Netback Calculation Continuing Operations 9 363 497 - 656 (179) 835 1,642 30 337 529 1 745 (404) 1,149 1,650 133 228 350 1 938 235 703 Basis of Netback Calculation Continuing Operations (45) (1) (77) - - - 33 33 (4) - - - 2 - 2 (8) - - - - (5) (3) (3) (15) (15) - 2 - - (2) (2) ABBREVIATIONS The following abbreviations have been used in this document: Crude Oil bbl Mbbls/d MMbbls BOE MMBOE WTI WCS CDB MSW Barrel thousand barrels per day million barrels barrel of oil equivalent million barrel of oil equivalent West Texas Intermediate Western Canadian Select Christina Dilbit Blend Mixed Sweet Blend NETBACK RECONCILIATIONS Natural Gas Mcf MMcf Bcf MMBtu GJ AECO NYMEX thousand cubic feet million cubic feet billion cubic feet million British thermal units gigajoule Alberta Energy Company New York Mercantile Exchange The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Consolidated Financial Statements. Total Production From Continuing Operations Continuing Upstream Financial Results Year Ended December 31, 2017 ($ millions) Oil Sands (1) Deep Basin (1) Continuing Operations Condensate Inventory Other Per Consolidated Financial Statements Adjustments Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 7,362 230 3,704 934 - 2,494 307 2,187 555 41 56 250 1 207 - 207 7,917 271 3,760 1,184 1 2,701 307 2,394 (3,050) - (3,050) - - - - - - - - - - - - - (45) - (1) (77) - 33 - 33 Year Ended December 31, 2016 ($ millions) Oil Sands (1) Deep Basin (1) Continuing Operations Condensate Inventory Other Per Consolidated Financial Statements Adjustments Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2015 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 2,929 9 1,721 501 - 698 (179) 877 - - - - - - - - 2,929 9 1,721 501 - 698 (179) 877 (1,402) - (1,402) - - - - - - - 44 - - (44) - (44) (2) - - (4) - 2 - 2 Per Consolidated Financial Statements Adjustments Oil Sands (1) Deep Basin (1) Conventional (2) Continuing Operations Condensate Inventory Other 3,030 29 1,815 531 - 655 (404) 1,059 - - - - - - - - 61 1 1 3 1 55 - 55 3,091 30 1,816 534 1 710 (404) 1,114 (1,441) - (1,441) - - - - - - - (38) - - 38 - 38 (8) - - (5) - (3) - (3) Per Interim Consolidated Financial Statements Continuing Operations Deep Basin (3) Oil Sands (3) Adjustments Condensate Inventory Other 2,424 113 1,193 271 - 847 235 612 231 20 24 94 1 92 - 92 2,655 133 1,217 365 1 939 235 704 (990) - (990) - - - - - - - (1) - - 1 - 1 (15) - 2 (15) - (2) - (2) Basis of Netback Calculation Continuing Operations 4,822 271 709 1,107 1 2,734 307 2,427 Basis of Netback Calculation Continuing Operations 1,525 9 363 497 - 656 (179) 835 Basis of Netback Calculation Continuing Operations 1,642 30 337 529 1 745 (404) 1,149 Basis of Netback Calculation Continuing Operations 1,650 133 228 350 1 938 235 703 2017 ANNUAL REPORT | 123 Three Months Ended September 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating (4) Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating (5) Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended March 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Per Interim Consolidated Financial Statements Continuing Operations Deep Basin (3) Oil Sands (3) Adjustments Condensate Inventory Other 2,210 54 1,066 259 - 831 9 822 200 13 22 101 - 64 - 64 2,410 67 1,088 360 - 895 9 886 (863) - (863) - - - - - - - 1 - - (1) - (1) (19) - (1) (9) - (9) - (9) Per Interim Consolidated Financial Statements Continuing Operations Deep Basin (3) Oil Sands (3) Adjustments Condensate Inventory Other 1,666 36 879 264 - 487 (14) 501 124 8 10 55 - 51 - 51 1,790 44 889 319 - 538 (14) 552 (719) - (719) - - - - - - - - - - - - - (6) - (2) (52) - 48 - 48 Per Interim Consolidated Financial Statements Continuing Operations Deep Basin (3) Oil Sands (3) Adjustments Condensate Inventory Other 1,062 27 566 140 - 329 77 252 - - - - - - - - 1,062 27 566 140 - 329 77 252 (478) - (478) - - - - - - - - - - - - - (5) - - (1) - (4) - (4) Basis of Netback Calculation Continuing Operations 1,528 67 225 351 - 885 9 876 Basis of Netback Calculation Continuing Operations 1,065 44 168 267 - 586 (14) 600 Basis of Netback Calculation Continuing Operations 579 27 88 139 - 325 77 248 (1) (2) (3) (4) (5) Found in Note 1 of the Consolidated Financial Statements. Includes the results of operation for certain Conventional segment royalty interest assets disposed of in 2015. Found in Note 1 of the Interim Consolidated Financial Statements. As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands segment were increased by $2 million in the third quarter of 2017. As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands and Deep Basin segments were increased by $43 million and $4 million, respectively, in the second quarter of 2017. Three Months Ended June 30, 2017 ($ millions) Foster Creek Christina Lake Crude Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Adjustments Oil Sands Year Ended December 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Netback (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2016 ($ millions) Gross Sales Royalties Transportation and Blending Operating Netback (Gain) Loss on Risk Management Operating Margin Foster Creek 1,945 178 387 465 915 131 784 Basis of Netback Calculation Total Crude Oil Christina Lake 2,345 52 266 403 1,624 176 1,448 4,290 230 653 868 2,539 307 2,232 Natural Gas Condensate Inventory Other Adjustments Per Consolidated Financial Statements (1) Total Oil Sands 8 - - 9 (1) - (1) 3,050 - 3,050 - - - - - - - - - - - 14 - 1 57 (44) - (44) 7,362 230 3,704 934 2,494 307 2,187 Foster Creek Basis of Netback Calculation Total Crude Oil Christina Lake 773 - 225 269 279 (90) 369 736 9 137 217 373 (89) 462 1,509 9 362 486 652 (179) 831 Natural Gas Condensate Inventory Other Adjustments Per Consolidated Financial Statements (1) Total Oil Sands 16 - 1 11 4 - 4 1,402 - 1,402 - - - - - - (44) - 44 - 44 2 - - 4 (2) - (2) 2,929 9 1,721 501 698 (179) 877 124 | CENOVUS ENERGY Three Months Ended September 30, 2017 ($ millions) Foster Creek Christina Lake Crude Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Adjustments (1) (1) Year Ended December 31, 2015 ($ millions) Foster Creek Christina Lake Crude Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Adjustments Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin 792 11 208 295 278 (202) 480 767 18 127 216 406 (198) 604 Three Months Ended December 31, 2017 ($ millions) Foster Creek Christina Lake Crude Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Adjustments Total 1,559 29 335 511 684 (400) 1,084 Total 1,430 113 202 260 855 235 620 Total 1,340 54 205 254 827 9 818 Total 943 36 158 218 531 (14) 545 Total 577 27 88 136 326 77 249 22 - 1 6 15 (4) 10 1 - - 3 - (2) (2) 1 - - 1 - - - 4 - - 2 2 - 2 2 - - 3 - (1) (1) 1,441 1,441 - - - - - - - - - - - - - - - - - - - - - - - - - 990 990 863 863 719 719 478 478 - - - - 38 (38) (38) - - 1 - - (1) (1) - - - 1 - 1 - - - - - - - - - - - - - - 626 91 106 137 292 98 194 603 43 126 138 296 2 294 429 24 100 119 186 (9) 195 287 20 55 71 141 40 101 804 22 96 123 563 137 426 737 11 79 116 531 7 524 514 12 58 99 345 (5) 350 290 7 33 65 185 37 148 Per Consolidated Financial Statements (1) Total Oil Sands Per Interim Consolidated Financial Statements (2) Total Oil Sands Per Interim Consolidated Financial Statements (2) Total Oil Sands Per Interim Consolidated Financial Statements (2) Total Oil Sands 1,666 Per Interim Consolidated Financial Statements (2) Total Oil Sands 1,062 3,030 29 1,815 531 655 (404) 1,059 2,424 113 1,193 271 847 235 612 2,210 54 1,066 259 831 9 822 36 879 264 487 (14) 501 27 566 140 329 77 252 3 - - 8 - (5) (5) 8 - - 5 3 - 3 6 - 4 3 - 3 5 - - 1 4 - 4 - - 2 - 44 (46) (46) Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin Transportation and Blending Gross Sales Royalties Operating (3) Netback (Gain) Loss on Risk Management Operating Margin Transportation and Blending Gross Sales Royalties Operating (3) Netback (Gain) Loss on Risk Management Operating Margin Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended March 31, 2017 ($ millions) Foster Creek Christina Lake Crude Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Adjustments (1) (2) (3) Found in Note 1 of the Consolidated Financial Statements. Found in Note 1 of the Interim Consolidated Financial Statements. As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $43 million and $2 million in the second and third quarters of 2017, respectively. Three Months Ended September 30, 2017 ($ millions) Gross Sales Royalties Operating (4) Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Operating (5) Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended March 31, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin (1) (2) (3) (4) (5) 2017. Oil Sands Year Ended December 31, 2017 ($ millions) Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin Per Interim Consolidated Financial Statements Adjustments Oil Sands (3) Deep Basin (3) Condensate Inventory Other Continuing Operations 2,210 54 1,066 259 831 - 9 822 36 879 264 - 487 (14) 501 1,062 27 566 140 - 329 77 252 200 101 13 22 64 - - 64 8 10 55 51 - - 51 - - - - - - - - 2,410 67 1,088 360 895 - 9 886 44 889 319 - 538 (14) 552 1,062 27 566 140 - 329 77 252 (863) (863) (719) (719) (478) (478) - - - - - - - - - - - - - - - - - - Per Interim Consolidated Financial Statements Adjustments Oil Sands (3) Deep Basin (3) Condensate Inventory Other Continuing Operations 1,666 124 1,790 Per Interim Consolidated Financial Statements Adjustments Oil Sands (3) Deep Basin (3) Condensate Inventory Other Continuing Operations Basis of Netback Calculation Continuing Operations (19) 1,528 (1) (9) (9) - - - (9) (6) (2) (52) - - - 48 48 (5) - - - - (1) (4) (4) 14 - 1 57 (44) - (44) 2 - - 4 - (2) (2) 67 225 351 885 - 9 876 Basis of Netback Calculation Continuing Operations 1,065 44 168 267 - 586 (14) 600 Basis of Netback Calculation Continuing Operations 579 27 88 139 - 325 77 248 Per Consolidated Financial Statements (1) Total Oil Sands Per Consolidated Financial Statements (1) Total Oil Sands 7,362 230 3,704 934 2,494 307 2,187 2,929 9 1,721 501 698 (179) 877 - - 1 - - - (1) (1) - - - - - - - - - - - - - - - - - - - - - - - (44) - - - - 44 44 Found in Note 1 of the Consolidated Financial Statements. Includes the results of operation for certain Conventional segment royalty interest assets disposed of in 2015. Found in Note 1 of the Interim Consolidated Financial Statements. As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands segment were increased by $2 million in the third quarter of 2017. As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands and Deep Basin segments were increased by $43 million and $4 million, respectively, in the second quarter of Basis of Netback Calculation Adjustments Crude Oil Natural Gas Condensate Inventory Other Foster Creek 1,945 178 387 465 915 131 784 Christina Lake 2,345 52 266 403 1,624 176 1,448 Total 4,290 230 653 868 2,539 307 2,232 Total 1,509 9 362 486 652 (179) 831 8 - - 9 - (1) (1) 16 11 - 1 4 - 4 3,050 3,050 1,402 1,402 - - - - - - - - - - Year Ended December 31, 2016 ($ millions) Foster Creek Christina Lake Crude Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Adjustments Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin 773 - 225 269 279 (90) 369 736 9 137 217 373 (89) 462 Year Ended December 31, 2015 ($ millions) Gross Sales Royalties Transportation and Blending Operating Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended September 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating (3) Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating (3) Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended March 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Netback (Gain) Loss on Risk Management Operating Margin Per Consolidated Financial Statements (1) Total Oil Sands 3,030 29 1,815 531 655 (404) 1,059 Per Interim Consolidated Financial Statements (2) Total Oil Sands Foster Creek Basis of Netback Calculation Total Crude Oil Christina Lake 792 11 208 295 278 (202) 480 767 18 127 216 406 (198) 604 1,559 29 335 511 684 (400) 1,084 Natural Gas Condensate Inventory Other Adjustments 22 - 1 15 6 (4) 10 1,441 - 1,441 - - - - - - 38 - (38) - (38) 8 - - 5 3 - 3 Foster Creek Basis of Netback Calculation Total Crude Oil Christina Lake 626 91 106 137 292 98 194 804 22 96 123 563 137 426 1,430 113 202 260 855 235 620 Foster Creek Basis of Netback Calculation Total Crude Oil Christina Lake 603 43 126 138 296 2 294 737 11 79 116 531 7 524 1,340 54 205 254 827 9 818 Natural Gas Condensate Inventory Other Adjustments 1 - - 3 (2) - (2) 990 - 990 - - - - - - 1 - (1) - (1) 3 - - 8 (5) - (5) 2,424 113 1,193 271 847 235 612 Natural Gas Condensate Inventory Other Adjustments Per Interim Consolidated Financial Statements (2) Total Oil Sands 1 - - 1 - - - 863 - 863 - - - - - - (1) - 1 - 1 6 - (1) 4 3 - 3 2,210 54 1,066 259 831 9 822 Foster Creek Basis of Netback Calculation Total Crude Oil Christina Lake 429 24 100 119 186 (9) 195 514 12 58 99 345 (5) 350 943 36 158 218 531 (14) 545 Natural Gas Condensate Inventory Other Adjustments Per Interim Consolidated Financial Statements (2) Total Oil Sands 4 - - 2 2 - 2 719 - 719 - - - - - - - - - - - - - 2 44 (46) - (46) 1,666 36 879 264 487 (14) 501 Foster Creek Basis of Netback Calculation Total Crude Oil Christina Lake 287 20 55 71 141 40 101 290 7 33 65 185 37 148 577 27 88 136 326 77 249 Natural Gas Condensate Inventory Other Adjustments 2 - - 3 (1) - (1) 478 - 478 - - - - - - - - - - - 5 - - 1 4 - 4 Per Interim Consolidated Financial Statements (2) Total Oil Sands 1,062 27 566 140 329 77 252 (1) (2) (3) Found in Note 1 of the Consolidated Financial Statements. Found in Note 1 of the Interim Consolidated Financial Statements. As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $43 million and $2 million in the second and third quarters of 2017, respectively. 2017 ANNUAL REPORT | 125 Deep Basin Year Ended December 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended September 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating (3) Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Basis of Netback Calculation Total 524 41 56 230 1 196 - 196 Basis of Netback Calculation Total 219 20 26 87 1 85 - 85 Basis of Netback Calculation Total 187 13 20 96 - 58 - 58 Basis of Netback Calculation Total 118 8 10 47 - 53 - 53 Per Consolidated Financial Statements (1) Total Deep Basin Adjustments Other 31 - - 20 - 11 - 11 555 41 56 250 1 207 - 207 Per Interim Consolidated Financial Statements (2) Total Deep Basin Adjustments Other 12 - (2) 7 - 7 - 7 231 20 24 94 1 92 - 92 Per Interim Consolidated Financial Statements (2) Total Deep Basin Adjustments Other 13 - 2 5 - 6 - 6 200 13 22 101 - 64 - 64 Per Interim Consolidated Financial Statements (2) Total Deep Basin Adjustments Other 6 - - 8 - (2) - (2) 124 8 10 55 - 51 - 51 (1) (2) (3) Found in Note 1 of the Consolidated Financial Statements. Found in Note 1 of the Interim Consolidated Financial Statements. As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $4 million in the second quarter of 2017. Conventional (Discontinued Operations) Year Ended December 31, 2017 ($ millions) Heavy Oil Light & Medium NGLs Conventional Liquids Natural Gas Conventional Condensate Inventory Other Basis of Netback Calculation Adjustments Per Consolidated Financial Statements(1) Total Conventional Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 383 51 35 117 - 180 14 166 504 107 25 153 17 202 23 179 17 2 - - - 15 - 15 904 160 60 270 17 397 37 360 300 14 12 152 1 121 (4) 125 1,204 174 72 422 18 518 33 485 95 - 95 - - - - - - - - - - - - - 10 - - 4 - 6 - 6 1,309 174 167 426 18 524 33 491 126 | CENOVUS ENERGY December 31, 2016 ($ millions) Heavy Oil NGLs Liquids Gas Conventional Condensate Inventory Other Conventional Basis of Netback Calculation Conventional Natural Light & Medium December 31, 2015 ($ millions) Heavy Oil NGLs Liquids Gas Conventional Condensate Inventory Other Conventional Basis of Netback Calculation Conventional Natural Light & Medium December 31, 2017 ($ millions) Heavy Oil NGLs Liquids Gas Conventional Condensate Inventory Other Conventional Basis of Netback Calculation Conventional Natural Adjustments Year Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Year Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin 380 35 49 142 - 154 (34) 188 507 39 44 206 - 218 (88) 306 40 2 3 - 14 21 4 17 17 13 35 - 46 1 45 16 11 37 - 55 2 53 442 88 25 149 12 168 (30) 198 528 62 31 180 15 240 (76) 316 Light & Medium 107 24 32 5 4 42 13 29 26 7 44 4 50 3 47 28 7 39 5 59 1 58 11 2 - - - 9 - 9 13 1 - - - - 12 12 4 - - - - 4 - 4 4 1 - - - 3 - 3 4 - - - - 4 - 4 833 125 74 291 12 331 (64) 395 1,048 102 75 386 15 470 (164) 634 151 26 46 8 4 67 17 50 246 44 20 79 4 99 4 95 261 44 18 76 5 118 3 115 319 14 16 154 135 - - 135 435 11 17 177 2 228 (55) 283 53 2 2 - 35 14 (3) 17 62 3 3 39 - 17 (1) 18 90 5 3 - - 37 45 45 1,152 139 90 445 12 466 (64) 530 1,483 113 92 563 17 698 (219) 917 204 28 10 81 4 81 14 67 308 47 23 118 116 4 3 113 351 49 21 113 163 5 3 160 - - - - - - - - - - - - 8 - 8 - - - - - 22 22 - - - - - - 32 32 - - - - - - Adjustments 103 103 (7) Adjustments 142 142 (5) Per Consolidated Financial Statements(1) Total Per Consolidated Financial Statements(1) Total 1,267 139 186 444 12 486 (58) 544 1,648 113 229 558 17 731 (209) 940 Per Interim Consolidated Financial Statements(2) Total Per Interim Consolidated Financial Statements(2) Total Per Interim Consolidated Financial Statements(2) Total 218 29 18 83 4 84 14 70 331 45 44 118 120 4 3 117 386 50 54 115 162 5 3 159 12 - - - (1) 13 6 7 23 - - - (5) 28 10 18 6 1 - 2 - 3 - 3 1 (2) (1) - - 4 - 4 3 1 1 2 - - (1) (1) - - - - 7 - 7 - - - - 5 - 5 - - - - - - - - - - - - - - - - - - - - - - - - Heavy Oil NGLs Liquids Gas Conventional Condensate Inventory Other Conventional Basis of Netback Calculation Conventional Natural Adjustments Light & Medium 119 138 September 30, 2017 ($ millions) Heavy Oil NGLs Liquids Gas Conventional Condensate Inventory Other Conventional Basis of Netback Calculation Conventional Natural Adjustments Light & Medium 111 131 Year Ended December 31, 2017 ($ millions) Total Other Total Deep Basin Deep Basin Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended September 30, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Operating (3) Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements (2) Other Total Deep Basin Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements (2) Other Total Deep Basin Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements (2) Other Total Deep Basin 524 41 56 230 196 1 - 196 Total 219 20 26 87 1 85 - 85 Total 187 13 20 96 58 - - 58 Total 118 8 10 47 53 - - 53 555 41 56 250 207 1 - 207 231 20 24 94 1 92 - 92 200 101 13 22 64 - - 64 124 8 10 55 51 - - 51 31 - - - - 20 11 11 12 - (2) 7 - 7 - 7 13 - 2 5 - 6 - 6 6 - - 8 - - (2) (2) (1) (2) (3) Found in Note 1 of the Consolidated Financial Statements. Found in Note 1 of the Interim Consolidated Financial Statements. As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $4 million in the second quarter of 2017. Conventional (Discontinued Operations) December 31, 2017 ($ millions) Heavy Oil NGLs Liquids Gas Conventional Condensate Inventory Other Conventional Basis of Netback Calculation Conventional Natural Adjustments Year Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Light & Medium 504 107 25 153 17 202 23 179 383 51 35 117 - 180 14 166 17 2 - - - - 15 15 904 160 60 270 17 397 37 360 300 14 12 152 1 121 (4) 125 1,204 174 72 422 18 518 33 485 95 95 - - - - - - - - - - - - - - Per Consolidated Financial Statements(1) Total 10 1,309 - - 4 - 6 - 6 174 167 426 18 524 33 491 Basis of Netback Calculation Adjustments Per Consolidated Financial Statements (1) Year Ended December 31, 2016 ($ millions) Heavy Oil Light & Medium NGLs Conventional Liquids Natural Gas Conventional Condensate Inventory Other Basis of Netback Calculation Adjustments Per Consolidated Financial Statements(1) Total Conventional Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 380 35 49 142 - 154 (34) 188 442 88 25 149 12 168 (30) 198 11 2 - - - 9 - 9 833 125 74 291 12 331 (64) 395 319 14 16 154 - 135 - 135 1,152 139 90 445 12 466 (64) 530 103 - 103 - - - - - - - (7) - - 7 - 7 12 - - (1) - 13 6 7 1,267 139 186 444 12 486 (58) 544 Year Ended December 31, 2015 ($ millions) Heavy Oil Light & Medium NGLs Conventional Liquids Natural Gas Conventional Condensate Inventory Other Basis of Netback Calculation Adjustments Per Consolidated Financial Statements(1) Total Conventional Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 507 39 44 206 - 218 (88) 306 528 62 31 180 15 240 (76) 316 13 1 - - - 12 - 12 1,048 102 75 386 15 470 (164) 634 435 11 17 177 2 228 (55) 283 1,483 113 92 563 17 698 (219) 917 142 - 142 - - - - - - - (5) - - 5 - 5 23 - - (5) - 28 10 18 1,648 113 229 558 17 731 (209) 940 Three Months Ended December 31, 2017 ($ millions) Heavy Oil Light & Medium NGLs Conventional Liquids Natural Gas Conventional Condensate Inventory Other Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(2) Total Conventional Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 40 2 3 14 - 21 4 17 107 24 5 32 4 42 13 29 4 - - - - 4 - 4 151 26 8 46 4 67 17 50 53 2 2 35 - 14 (3) 17 204 28 10 81 4 81 14 67 8 - 8 - - - - - - - - - - - - - 6 1 - 2 - 3 - 3 218 29 18 83 4 84 14 70 Three Months Ended September 30, 2017 ($ millions) Heavy Oil Light & Medium NGLs Conventional Liquids Natural Gas Conventional Condensate Inventory Other Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(2) Total Conventional Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 111 17 13 35 - 46 1 45 131 26 7 44 4 50 3 47 4 1 - - - 3 - 3 246 44 20 79 4 99 4 95 62 3 3 39 - 17 (1) 18 308 47 23 118 4 116 3 113 22 - 22 - - - - - - - - - - - - - 1 (2) (1) - - 4 - 4 331 45 44 118 4 120 3 117 Three Months Ended June 30, 2017 ($ millions) Heavy Oil Light & Medium NGLs Conventional Liquids Natural Gas Conventional Condensate Inventory Other Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(2) Total Conventional Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 119 16 11 37 - 55 2 53 138 28 7 39 5 59 1 58 4 - - - - 4 - 4 261 44 18 76 5 118 3 115 90 5 3 37 - 45 - 45 351 49 21 113 5 163 3 160 32 - 32 - - - - - - - - - - - - - 3 1 1 2 - (1) - (1) 386 50 54 115 5 162 3 159 2017 ANNUAL REPORT | 127 Three Months Ended September 30, 2017 ($ millions) Continuing Operations (1) Conventional (3) Operations Condensate Inventory Other Operations Per Interim Consolidated Financial Statements Adjustments Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended March 31, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Per Interim Consolidated Financial Statements Adjustments Continuing Operations (1) Conventional (3) Operations Condensate Inventory Other Operations Total 2,741 112 1,132 478 4 1,015 12 1,003 Total 2,176 94 943 434 5 700 (11) 711 Total 1,436 77 617 250 5 487 90 397 331 45 44 118 120 4 3 117 386 50 54 115 162 5 3 159 374 50 51 110 5 158 13 145 (885) (885) (751) (751) (511) (511) - - - - - - - - - - - - - - - - - - 2,410 67 1,088 360 895 - 9 886 1,790 44 889 319 - 538 (14) 552 1,062 27 566 140 - 329 77 252 Basis of Netback Calculation Total Basis of Netback Calculation Total Basis of Netback Calculation Total 1,836 114 248 469 4 1,001 12 989 1,416 93 189 380 5 749 (11) 760 920 77 106 249 5 483 90 393 (20) 2 - - - (9) (13) (13) (9) (1) (3) (54) 49 - - 49 (5) - - - - (1) (4) (4) - - 1 - - - (1) (1) - - - - - - - - - - - - - - - - Per Interim Consolidated Financial Statements Adjustments Continuing Operations (1) Conventional (3) Operations Condensate Inventory Other Operations (1) (2) (3) Continuing operations consist of the Oil Sands and Deep Basin segments. Classified as a discontinued operation, which can be found in Note 11 of the Consolidated Financial Statements. Classified as a discontinued operation, which can be found in Note 9 of the Interim Consolidated Financial Statements. Three Months Ended March 31, 2017 ($ millions) Heavy Oil Light & Medium NGLs Conventional Liquids Natural Gas Conventional Condensate Inventory Other Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(2) Total Conventional Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 113 16 8 31 - 58 7 51 128 29 6 38 4 51 6 45 5 1 - - - 4 - 4 246 46 14 69 4 113 13 100 95 4 4 41 1 45 - 45 341 50 18 110 5 158 13 145 33 - 33 - - - - - - - - - - - - - - - - - - - - - 374 50 51 110 5 158 13 145 (1) (2) Found in Note 11 of the Consolidated Financial Statements and includes operating results associated with our royalty interest assets sold in 2015 consisting of gross sales, royalties, transportation and blending expenses, operating expenses, and production and mineral taxes in the amount of $61 million, $1 million, $1 million, $3 million and $1 million, respectively. Found in Note 8 of the Interim Consolidated Financial Statements. Total Production Upstream Financial Results Year Ended December 31, 2017 ($ millions) Per Consolidated Financial Statements Continuing Operations (1) Conventional (2) Total Operations Adjustments Condensate Inventory Other Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 7,917 271 3,760 1,184 1 2,701 307 2,394 1,309 174 167 426 18 524 33 491 9,226 445 3,927 1,610 19 3,225 340 2,885 (3,145) - (3,145) - - - - - - - - - - - - - (55) - (2) (81) - 28 - 28 Year Ended December 31, 2016 ($ millions) Per Consolidated Financial Statements Continuing Operations (1) Conventional (2) Total Operations Adjustments Condensate Inventory Other Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 2,929 9 1,721 501 - 698 (179) 877 1,267 139 186 444 12 486 (58) 544 4,196 148 1,907 945 12 1,184 (237) 1,421 (1,505) - (1,505) - - - - - - - 51 - - (51) - (51) (14) - - (3) - (11) (6) (5) Year Ended December 31, 2015 ($ millions) Per Consolidated Financial Statements Continuing Operations (1) Conventional (2) Total Operations Adjustments Condensate Inventory Other 3,091 30 1,816 534 1 710 (404) 1,114 1,648 113 229 558 17 731 (209) 940 4,739 143 2,045 1,092 18 1,441 (613) 2,054 (1,583) - (1,583) - - - - - - - (33) - - 33 - 33 (31) - - - - (31) (10) (21) Per Interim Consolidated Financial Statements Total Operations Operations (1) Conventional (3) Continuing Adjustments Condensate Inventory Other 2,655 133 1,217 365 1 939 235 704 218 29 18 83 4 84 14 70 2,873 162 1,235 448 5 1,023 249 774 (998) - (998) - - - - - - - (1) - - 1 - 1 (21) (1) 1 (17) - (4) - (4) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 128 | CENOVUS ENERGY Basis of Netback Calculation Total Operations 6,026 445 780 1,529 19 3,253 340 2,913 Basis of Netback Calculation Total Operations 2,677 148 453 942 12 1,122 (243) 1,365 Basis of Netback Calculation Total Operations 3,125 143 429 1,092 18 1,443 (623) 2,066 Basis of Netback Calculation Total Operations 1,854 161 237 431 5 1,020 249 771 March 31, 2017 ($ millions) Heavy Oil NGLs Liquids Gas Conventional Condensate Inventory Other Conventional Basis of Netback Calculation Conventional Natural Adjustments Three Months Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Light & Medium 113 128 16 8 31 - 58 7 51 29 6 38 4 51 6 45 5 1 - - - 4 - 4 246 46 14 69 4 113 13 100 95 4 4 41 1 45 - 45 341 50 18 110 5 158 13 145 33 33 - - - - - - - - - - - - - - Per Interim Consolidated Financial Statements(2) Total - - - - - - - - 374 50 51 110 5 158 13 145 Found in Note 11 of the Consolidated Financial Statements and includes operating results associated with our royalty interest assets sold in 2015 consisting of gross sales, royalties, transportation and blending expenses, (1) (2) operating expenses, and production and mineral taxes in the amount of $61 million, $1 million, $1 million, $3 million and $1 million, respectively. Found in Note 8 of the Interim Consolidated Financial Statements. Total Production Upstream Financial Results Year Ended December 31, 2017 ($ millions) Operations Condensate Inventory Other Operations Continuing Operations (1) Conventional (2) Per Consolidated Financial Statements Adjustments Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin 7,917 271 3,760 1,184 1 2,701 307 2,394 2,929 1,721 501 9 - 698 (179) 877 3,091 30 1,816 534 1 710 (404) 1,114 2,655 133 1,217 365 1 939 235 704 1,309 174 167 426 18 524 33 491 1,267 139 186 444 12 486 (58) 544 1,648 113 229 558 17 731 (209) 940 218 29 18 83 4 84 14 70 Total 9,226 445 3,927 1,610 19 3,225 340 2,885 Total 4,196 148 1,907 945 12 1,184 (237) 1,421 Total 4,739 143 2,045 1,092 18 1,441 (613) 2,054 Total 2,873 162 1,235 448 5 1,023 249 774 (1,505) (1,505) 51 (1,583) (1,583) (33) (3,145) (3,145) - - - - - - - - - - - - - - - - - - - - - - - - (998) (998) - - - - - - - - - - - - - (51) (51) - - - - - 33 33 (1) - - - - 1 - 1 Basis of Netback Calculation Total Basis of Netback Calculation Total 6,026 445 780 1,529 19 3,253 340 2,913 2,677 148 453 942 12 1,122 (243) 1,365 3,125 143 429 1,092 18 1,443 (623) 2,066 1,854 161 237 431 5 1,020 249 771 Basis of Netback Calculation Total Basis of Netback Calculation Total (55) (2) (81) - - - 28 28 (14) - - - (3) (11) (6) (5) (31) - - - - (31) (10) (21) (21) (1) (17) 1 - - (4) (4) Year Ended December 31, 2015 ($ millions) Operations Condensate Inventory Other Operations Continuing Operations (1) Conventional (2) Per Consolidated Financial Statements Adjustments Three Months Ended December 31, 2017 ($ millions) Continuing Operations (1) Conventional (3) Operations Condensate Inventory Other Operations Per Interim Consolidated Financial Statements Adjustments Year Ended December 31, 2016 ($ millions) Operations Condensate Inventory Other Operations Continuing Operations (1) Conventional (2) Per Consolidated Financial Statements Adjustments Three Months Ended September 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended June 30, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Three Months Ended March 31, 2017 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin Per Interim Consolidated Financial Statements Total Operations Operations (1) Conventional (3) Continuing Adjustments Condensate Inventory Other 2,410 67 1,088 360 - 895 9 886 331 45 44 118 4 120 3 117 2,741 112 1,132 478 4 1,015 12 1,003 (885) - (885) - - - - - - - 1 - - (1) - (1) (20) 2 - (9) - (13) - (13) Per Interim Consolidated Financial Statements Total Operations Operations (1) Conventional (3) Continuing Adjustments Condensate Inventory Other 1,790 44 889 319 - 538 (14) 552 386 50 54 115 5 162 3 159 2,176 94 943 434 5 700 (11) 711 (751) - (751) - - - - - - - - - - - - - (9) (1) (3) (54) - 49 - 49 Per Interim Consolidated Financial Statements Total Operations Operations (1) Conventional (3) Continuing Adjustments Condensate Inventory Other 1,062 27 566 140 - 329 77 252 374 50 51 110 5 158 13 145 1,436 77 617 250 5 487 90 397 (511) - (511) - - - - - - - - - - - - - (5) - - (1) - (4) - (4) Basis of Netback Calculation Total Operations 1,836 114 248 469 4 1,001 12 989 Basis of Netback Calculation Total Operations 1,416 93 189 380 5 749 (11) 760 Basis of Netback Calculation Total Operations 920 77 106 249 5 483 90 393 (1) (2) (3) Continuing operations consist of the Oil Sands and Deep Basin segments. Classified as a discontinued operation, which can be found in Note 11 of the Consolidated Financial Statements. Classified as a discontinued operation, which can be found in Note 9 of the Interim Consolidated Financial Statements. 2017 ANNUAL REPORT | 129 The following table provides the sales volumes used to calculate Netback. Sales Volumes (barrels per day, unless otherwise stated) Oil Sands Foster Creek Christina Lake Total Oil Sands Crude Oil Natural Gas (MMcf per day) Deep Basin Total Liquids Natural Gas (MMcf per day) Conventional Sales (BOE per day) Twelve Months Ended December 31 2017 2016 2015 121,806 161,514 283,320 10 20,850 316 - 69,647 79,481 149,128 17 - - - 64,467 73,872 138,339 19 - - 4,163 Sales From Continuing Operations (BOE per day) 358,476 151,962 145,669 Conventional (Discontinued Operations) Heavy Oil Light and Medium Oil Natural Gas Liquids (“NGLs”) Total Conventional Liquids Natural Gas (MMcf per day) Sales From Discontinued Operations (BOE per day) Total Liquids Sales Total Sales (BOE per day) 21,669 24,571 1,073 47,313 333 102,792 351,483 28,958 25,965 1,065 55,988 377 118,821 205,116 34,965 28,706 1,149 64,820 412 133,537 205,706 461,268 270,783 279,206 Three Months Ended (barrels per day, unless otherwise stated) December 31, 2017 September 30, 2017 June 30, 2017 March 31, 2017 Oil Sands Foster Creek Christina Lake Total Oil Sands Crude Oil Natural Gas (MMcf per day) Deep Basin Total Liquids Natural Gas (MMcf per day) 143,586 193,734 337,320 7 33,147 509 157,850 206,338 364,188 6 32,864 495 106,115 154,431 260,546 12 16,894 253 78,562 89,919 168,481 15 - - Sales From Continuing Operations (BOE per day) 456,455 480,512 321,526 170,981 Conventional (Discontinued Operations) Heavy Oil Light and Medium Oil Natural Gas Liquids (“NGLs”) Total Conventional Liquids Natural Gas (MMcf per day) Sales From Discontinued Operations (BOE per day) Total Liquids Sales Total Sales (BOE per day) 7,485 18,915 913 27,313 279 73,775 397,780 25,047 27,494 1,201 53,742 350 112,079 450,794 28,089 26,835 1,132 56,056 355 115,235 333,496 26,222 25,074 1,047 52,343 348 110,343 220,824 530,230 592,591 436,761 281,324 130 | CENOVUS ENERGY I N F O R M A T I O N F O R SHAREHOLDERS ANNUAL MEETING Shareholders are invited to attend the annual meeting of shareholders to be held on Wednesday, April 25, 2018 at 2 p.m. MST in the ballroom at the Metropolitan Conference Centre, 333-4 Avenue SW, Calgary. Please see our management information circular available on cenovus.com for additional information. TRANSFER AGENT & REGISTRAR Computershare Investor Services Inc. 8th Floor, 100 University Avenue Toronto, Ontario M5J 2Y1 Canada investorcentre.com/cenovus Shareholder inquiries by phone: North America 1.866.332.8898 (English and French) Outside North America 1.514.982.8717 (English and French) SHAREHOLDER ACCOUNT MATTERS For information regarding your shareholdings or to change your address, transfer shares, eliminate duplicate mailings, direct deposit of dividends, etc., please contact Computershare Investor Services Inc. STOCK EXCHANGES Cenovus common shares trade on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol CVE. ANNUAL INFORMATION FORM/FORM 40-F Our Annual Information Form is filed with the Canadian Securities Administrators in Canada on SEDAR at sedar.com and with the U.S. Securities and Exchange Commission under the Multi-Jurisdictional Disclosure System as an Annual Report on Form 40-F on EDGAR at sec.gov. NYSE CORPORATE GOVERNANCE STANDARDS As a Canadian company listed on the NYSE, we are not required to comply with most of the NYSE corporate governance standards and instead may comply with Canadian corporate governance requirements. We are, however, required to disclose the significant differences between our corporate governance practices and those required to be followed by U.S. domestic companies under the NYSE corporate governance standards. Except as summarized on cenovus.com, we are in compliance with the NYSE corporate governance standards in all significant respects. INVESTOR RELATIONS Please visit the Investors section at cenovus.com for investor information. Investor inquiries should be directed to: 403.766.7711, investor.relations@cenovus.com Media inquiries should be directed to: 403.766.7751, media.relations@cenovus.com CENOVUS HEAD OFFICE Cenovus Energy Inc. 500 Centre Street SE PO Box 766 Calgary, Alberta T2P 0M5 Canada Phone: 403.766.2000 cenovus.com CENOVUS’S LEADERSHIP TEAM (as at January 15, 2018) Alex Pourbaix Harbir Chhina Keith Chiasson Al Reid Ivor Ruste Sarah Walters Drew Zieglgansberger CENOVUS’S BOARD OF DIRECTORS (as at January 15, 2018) Patrick D. Daniel, Board Chair, Calgary, Alberta (3,7) Susan F. Dabarno, Bracebridge, Ontario (2,3,4) Ian W. Delaney, Toronto, Ontario (2,3,5) Alex J. Pourbaix, Calgary, Alberta (6) Steven F. Leer, Boca Grande, Florida (1,2,3) Richard J. Marcogliese, Alamo, California (3,4,5) Claude Mongeau, Montreal, Quebec (1,3,4) Charles M. Rampacek, Fredericksburg, Texas (2,3,5) Colin Taylor, Toronto, Ontario (1,3,4) Wayne G. Thomson, Calgary, Alberta (1,3,4) Rhonda I. Zygocki, Friday Harbor, Washington (2,3,5) (1) Member of the Audit Committee (2) Member of the Human Resources and Compensation Committee (3) Member of the Nominating and Corporate Governance Committee (4) Member of the Reserves Committee (5) Member of the Safety, Environment and Responsibility Committee (6) As an officer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board (7) Ex-officio non-voting member of all other committees of Cenovus’s Board a d a n a C n i d e t n i r P CENOVUS ENERGY INC. Cenovus Energy Inc. is a Canadian integrated oil and natural gas company. It is committed to maximizing value by responsibly developing its assets in a safe, innovative and efficient way. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and British Columbia. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. For more information, visit cenovus.com. c e n o v u s . c o m 500 Centre Street SE PO Box 766 Calgary, Alberta T2P 0M5 Canada 

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