Cenovus Energy Annual Report 2018

Plain-text annual report

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 E N E R G Y 2 0 1 8 A N N U A L R E P O R T c e n o v u s . c o m 500 Centre Street SE, PO Box 766, Calgary, Alberta T2P 0M5, Canada F SC FPO 2018 ANNUAL REPORT I N F O R M A T I O N F O R SHAREHOLDERS ANNUAL MEETING INVESTOR RELATIONS Shareholders are invited to attend the annual meeting Please visit the Investors section at cenovus.com for of shareholders to be held on Wednesday, April 24, investor information. 2019 at 1 p.m. MT 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. 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 TRANSFER AGENT & REGISTRAR Computershare Investor Services Inc. 8th Floor, 100 University Avenue Toronto, Ontario M5J 2Y1 Canada www.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. If your shares are held by a broker, please contact your broker. 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 ﬁ led 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 signiﬁ cant 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 www.cenovus.com/about/governance/key-governance- documents.html, we are in compliance with the NYSE corporate governance standards in all signiﬁ cant respects. CENOVUS HEAD OFFICE Cenovus Energy Inc. 500 Centre Street SE PO Box 766 Phone: 403.766.2000 cenovus.com Calgary, Alberta T2P 0M5 Canada CENOVUS’S LEADERSHIP TEAM (as at March 1, 2019) Alex Pourbaix, President & Chief Executive Ofﬁ cer Harbir Chhina, EVP & Chief Technology Ofﬁ cer Keith Chiasson, EVP, Downstream Jon McKenzie, EVP & Chief Financial Ofﬁ cer Al Reid, EVP, Stakeholder Engagement, Safety, Legal & General Counsel Kam Sandhar, SVP, Strategy & Corporate Development Sarah Walters, SVP, Corporate Services Drew Zieglgansberger, EVP, Upstream CENOVUS’S BOARD OF DIRECTORS (as at March 1, 2019) Patrick D. Daniel, Board Chair, Calgary, Alberta (7) Susan F. Dabarno, Bracebridge, Ontario (1,3,4) Alex J. Pourbaix, Calgary, Alberta (6) Harold N. Kvisle, Calgary, Alberta (1,3,5) Steven F. Leer, Boca Grande, Florida (2,3,4) Keith A. MacPhail, Calgary, Alberta (2,3,4) Richard J. Marcogliese, Alamo, California (2,5) Claude Mongeau, Montreal, Quebec (1,3,5) Charles M. Rampacek, Fredericksburg, Texas (2, 5) Colin Taylor, Toronto, Ontario (1, 4) Wayne G. Thomson, Calgary, Alberta (1,4) Rhonda I. Zygocki, Friday Harbor, Washington (2,5) (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 ofﬁ cer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board (7) Ex-ofﬁ cio non-voting member of all committees of Cenovus’s Board a d a n a C n i d e t n i r P 2018 ANNUAL REPORT | 133 Demonstrating industry-leading cost discipline The phase G expansion at Cenovus’s Christina Lake oil sands project is a great example of our continuing focus on capital discipline. The project is several months ahead of schedule and is an estimated 25% below budget, largely due to advances in well pad design, longer well lengths and increased efﬁ ciencies in facility construction. We expect Christina Lake phase G will be completed with industry-leading capital efﬁ ciencies of between $15,000 and $16,000 per barrel of capacity. Working with Aboriginal communities We work to develop mutually beneﬁ cial relationships with Aboriginal communities near our operations and aim to procure goods and services from local providers whenever possible. In 2018, we spent approximately $200 million purchasing everything from camp catering to well and earthworks services from local Aboriginal businesses. Since becoming a standalone company in December 2009, Cenovus has spent more than $2.7 billion doing business with Aboriginal companies in the areas where we operate. TABLE OF CONTENTS 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 63 CONSOLIDATED FINANCIAL STATEMENTS 72 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 117 SUPPLEMENTAL INFORMATION 120 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 120. 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 24, 2019 at 1 p.m. MT 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 www.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. If your shares are held by a broker, please contact your broker. ANNUAL INFORMATION FORM/FORM 40-F Our Annual Information Form is ﬁ led 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. OUR VISION OUR MISSION NYSE CORPORATE GOVERNANCE STANDARDS To be the energy company of choice for investors, staff As a Canadian company listed on the NYSE, we are not and stakeholders. 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 signiﬁ cant 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 www.cenovus.com/about/governance/key-governance- documents.html, we are in compliance with the NYSE corporate governance standards in all signiﬁ cant respects. To maximize the value of the company by responsibly developing oil and natural gas assets in a safe, innovative and efficient way. 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 March 1, 2019) Alex Pourbaix, President & Chief Executive Ofﬁ cer Harbir Chhina, EVP & Chief Technology Ofﬁ cer Keith Chiasson, EVP, Downstream Jon McKenzie, EVP & Chief Financial Ofﬁ cer Al Reid, EVP, Stakeholder Engagement, Safety, Legal & General Counsel Kam Sandhar, SVP, Strategy & Corporate Development Sarah Walters, SVP, Corporate Services Drew Zieglgansberger, EVP, Upstream OUR VALUES CENOVUS’S BOARD OF DIRECTORS (as at March 1, 2019) Patrick D. Daniel, Board Chair, Calgary, Alberta (7) Susan F. Dabarno, Bracebridge, Ontario (1,3,4) Alex J. Pourbaix, Calgary, Alberta (6) Harold N. Kvisle, Calgary, Alberta (1,3,5) Steven F. Leer, Boca Grande, Florida (2,3,4) Keith A. MacPhail, Calgary, Alberta (2,3,4) Richard J. Marcogliese, Alamo, California (2,5) Claude Mongeau, Montreal, Quebec (1,3,5) Charles M. Rampacek, Fredericksburg, Texas (2, 5) Integrity Colin Taylor, Toronto, Ontario (1, 4) We are transparent, honest and treat everyone with respect. Wayne G. Thomson, Calgary, Alberta (1,4) Rhonda I. Zygocki, Friday Harbor, Washington (2,5) Safety Safety before all else. STOCK EXCHANGES Cenovus common shares trade on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol CVE. We are a Canadian integrated oil and natural gas company Cenovus operates oil sands projects in northern Alberta that use a technique called steam-assisted gravity drainage (SAGD). We also have established crude oil, natural gas liquids and natural gas production in the Deep Basin in Alberta and British Columbia as well as 50 percent interest in two U.S. refineries operated by Phillips 66. The photo above shows steam generators at our Christina Lake oil sands operations. Performance We work as one team to make smart decisions that deliver results. (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 ofﬁ cer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board (7) Ex-ofﬁ cio non-voting member of all committees of Cenovus’s Board Accountability We do what we say we will do. a d a n a C n i d e t n i r P 2018 ANNUAL REPORT | 1 2018 ANNUAL REPORT | 133 Demonstrating industry-leading cost discipline Working with Aboriginal communities The phase G expansion at Cenovus’s Christina Lake oil sands project is a We work to develop mutually beneﬁ cial relationships with Aboriginal great example of our continuing focus on capital discipline. The project communities near our operations and aim to procure goods and is several months ahead of schedule and is an estimated 25% below services from local providers whenever possible. In 2018, we spent budget, largely due to advances in well pad design, longer well approximately $200 million purchasing everything from camp catering lengths and increased efﬁ ciencies in facility construction. We expect to well and earthworks services from local Aboriginal businesses. Since Christina Lake phase G will be completed with industry-leading capital becoming a standalone company in December 2009, Cenovus has efﬁ ciencies of between $15,000 and $16,000 per barrel of capacity. spent more than $2.7 billion doing business with Aboriginal companies in the areas where we operate. TABLE OF CONTENTS VISION, MISSION AND VALUES MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER MESSAGE FROM OUR BOARD CHAIR 1 2 4 5 MANAGEMENT’S DISCUSSION AND ANALYSIS 63 CONSOLIDATED FINANCIAL STATEMENTS 72 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 117 SUPPLEMENTAL INFORMATION 120 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 120. M E S S A G E F R O M O U R PRESIDENT & CHIEF EXECUTIVE OFFICER This past year was one of substantial achievement for Cenovus. In a very challenging environment for commodity prices, market access and energy policy, we focused on the things that were within our control and made considerable progress in delivering on our commitments to shareholders. I’m pleased with our accomplishments in further improving our business and deleveraging our balance sheet in 2018. I had hoped to see a corresponding increase in Cenovus’s share price. However, ongoing challenges related to lack of market access, which resulted in record high differentials between West Texas Intermediate (WTI) and Western Canadian Select (WCS) prices, continued to weigh on stock valuations for all Canadian energy producers last year. That said, I am extremely encouraged that Cenovus had nearly $1.2 billion in combined free funds flow in the second and third quarters of 2018 when prices remained somewhat normalized. This was largely due to the continued improvements we’ve made over the last year and should send a positive signal to investors about the underlying strength and potential of our business. I believe we have taken the right steps to position Cenovus to generate significant free funds flow in a rising commodity price environment, and we will remain focused on continuing to build positive momentum in 2019. Before turning to some of our key accomplishments in 2018, I would like to talk briefly about safety. Last year, Cenovus recorded its best-ever total recordable injury frequency for the second year in a row. Unfortunately, early in 2018, we also reported a fatality involving a third-party service provider at our Christina Lake site. This tragic incident was unacceptable and serves as a sobering reminder that safety must remain the top priority in everything we do. In the aftermath of the incident we have worked to understand what went wrong and taken steps to increase safety training and reinforce our life-saving rules so everyone understands their role in maintaining a safe work site. We remain vigilant to ensure everyone who works for us gets home safely at the end of every shift. As I said earlier, we had much to be proud of in 2018. We continued to demonstrate cost leadership and capital discipline, reducing our net debt to $8.4 billion by the end of the year from about $13 billion immediately following our May 2017 asset acquisition. We remain on track to reduce our net debt to adjusted earnings before interest, taxes, depreciation and amortization ratio to less than two times. At our oil sands operations, we achieved record-low operating costs and industry-leading sustaining capital costs. Our Christina Lake phase G expansion is on track to set a new industry benchmark for capital efficiencies when it’s completed later this year. As promised, we eliminated bureaucracy and streamlined our workforce and management structure to align with our planned work for 2018, 2019 and beyond. And we have now offset part of our long-term office rent costs by subleasing almost 40 percent of The Bow building in Calgary. In recognition of the progress we’ve made in reducing our debt and cost structure, while also maintaining strong operating performance and accelerating our cash-generating potential, last fall S&P Global Ratings reaffirmed our BBB credit rating and improved our outlook to stable from negative, and Moody’s Investors Service upgraded our credit rating to Ba1 stable from Ba2 stable. On the energy policy front, we played a leading role within industry on key provincial and federal policy issues, including advocating for significant improvements to Bill C-69. To improve market access, we signed industry-leading three-year rail agreements to transport up to 100,000 barrels per day of heavy crude oil from northern Alberta to destinations on the U.S. Gulf Coast. Our oil sands facilities continued to demonstrate excellent operational performance in 2018, setting new company records for daily production during the second quarter, prior to the 2 | CENOVUS ENERGY 2018 TOTAL SHAREHOLDER RETURN 160 150 140 130 120 110 100 90 80 70 60 $130 $120 $110 $100 $90 $80 $70 December 31, 2017 March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 Cenovus Energy (TSX) S&P TSX Composite Index S&P TSX Energy Index This chart shows cumulative shareholder return for $100 invested (assuming quarterly reinvestment of dividends) over the period December 31, 2017 to December 31, 2018. Even at low-cycle prices, around US$45 WTI, Cenovus remains fully capable of covering its sustaining capital costs and current dividend. And importantly, with our low-cost base, top-tier assets and strong operations, we have among the best upside exposure in our industry to rising oil prices and narrowed differentials. The completion of Christina Lake phase G will also give us the option to add significant incremental production capacity once we see sustained improvements in market access and heavy oil pricing. With the consolidation of our Calgary staff into Brookfield Place already well underway, we anticipate creating a more collaborative work environment for our staff this year, while also offsetting some of our long-term real estate costs. As I approach my 18th month as CEO of Cenovus, I have never been more excited about our prospects. In 2019, we will remain committed to establishing a strong foundation for increasing shareholder value through continued debt reduction, cost leadership and capital discipline while maintaining safe and reliable operations. I want to thank all our teams for their hard work and dedication in 2018, and I look forward to continuing to deliver on our commitments to shareholders in the months ahead. /s/ Alex Pourbaix President & Chief Executive Officer widening of light-heavy oil price differentials caused by pipeline constraints in the latter half of the year. In response to the corresponding collapse in WCS prices, we voluntarily reduced our oil sands production and proved our ability to store mobilized barrels of oil in our oil sands reservoirs for sale later when prices improved. We also developed additional options to store oil in salt caverns during times of low heavy oil pricing. In early 2018, we completed a modest drilling and development program in the Deep Basin with encouraging initial well results. We also made further progress streamlining our Deep Basin business while reducing debt through the sale of the Cenovus Pipestone Partnership. And we initiated a program to optimize our Deep Basin operating model to reduce costs, improve efficiency and maximize value. In addition, our integrated business model continued to demonstrate its value in 2018 as low Canadian heavy oil prices created a feedstock cost advantage for our jointly owned U.S. refineries. For the year, our Refining and Marketing segment generated almost $1 billion in operating margin, helping offset the impact of low heavy oil prices on our upstream operations. Our refineries also completed major turnarounds last year and achieved sustained utilization rates above 100 percent resulting in increased processing capacity ratings for each facility. Following our successes in 2018, I believe we have a lot to look forward to this year and beyond. As a result of the Government of Alberta’s decision to temporarily curtail oil production starting in January, we began 2019 with considerably stronger WCS prices than we saw late last year when price differentials reached record highs. While we expect continued volatility, we anticipate differentials will remain improved through the balance of this year, compared with 2018, due to the continued ramp-up of rail transport capacity in Alberta. 2018 ANNUAL REPORT | 3 While public policy challenges around market access and the competitiveness of our industry remain, this past year brought new reasons for optimism. The Board appreciates the growing support evident among Canadians for pipeline projects and for establishing a government policy framework that recognizes the valuable contribution the oil and natural gas industry makes to the national economy. We are pleased to see Canadians becoming more vocal about the benefits our industry brings to the entire country. In closing, 2018 was a strong year for Cenovus in a difficult environment. I believe our shareholders should be confident in the strategic direction of the company. With its robust oil sands portfolio and decades of attractive development opportunities, Cenovus is focused on being the best oil sands operator in the world while maintaining diversity in the Deep Basin and the company’s refining and marketing business. Your Board is well positioned to provide strong and appropriate guidance and oversight for Cenovus in 2019 and beyond. /s/ Patrick Daniel Board Chair M E S S A G E F R O M O U R BOARD CHAIR In 2018, Cenovus made excellent progress in advancing and executing its business strategy. Outstanding oil sands operating results were achieved and strong returns were realized from the company’s jointly owned U.S. refineries. This has not been an easy task given the continuing challenges facing our industry, which are largely beyond the control of any single company. Cenovus also further strengthened its leadership and governance last year. In this difficult environment, the Board of Directors remains confident that Cenovus has a strong executive management team that understands the company’s business thoroughly and is taking the right steps to position us for long-term success. The Board is also encouraged by the feedback Cenovus continues to receive from its shareholders. At the beginning of October, as part of our robust shareholder engagement program, I and other Board members met directly with investor groups collectively representing about 40 percent of the company’s shares. While our shareholders clearly want more certainty around key industry issues such as market access, we heard strong support in our meetings for the direction the company is taking and for our continued focus on deleveraging, capital discipline and cost leadership. We also heard that there is increased confidence in the new management team led by Alex Pourbaix as Chief Executive Officer, that Cenovus is seen as better positioned than many of our peers to benefit from improved market access and rising heavy oil prices, and that we continue to have among the best assets and people in our industry. The process of Board renewal also continued in 2018 with the election of Hal Kvisle and Keith MacPhail as directors. The Board renewal process focuses on orderly succession of directors while maintaining an appropriate balance of diversity and skills. At this time, I would like to thank Colin Taylor and Charles Rampacek, who will not be standing for re-election, for their excellent service to Cenovus. 4 | CENOVUS ENERGY MANAGEMENT’S DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2018 6 7 8 10 13 18 OVERVIEW OF CENOVUS YEAR IN REVIEW 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 31 31 34 36 DISCONTINUED OPERATIONS QUARTERLY RESULTS OIL AND GAS RESERVES LIQUIDITY AND CAPITAL RESOURCES 40 RISK MANAGEMENT AND RISK FACTORS 55 CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES 59 CONTROL ENVIRONMENT 59 CORPORATE RESPONSIBILITY 59 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 12, 2019, should be read in conjunction with December 31, 2018 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 12, 2019, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. 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 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 12, 2019. 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 and Liquidity and Capital Resources sections of this MD&A as well as the Netback Reconciliations on page 124 and the Adjusted Funds Flow and Free Funds Flow Reconciliation on page 128. 2018 ANNUAL REPORT | 5 OVERVIEW OF CENOVUS Refining and Marketing 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, 2018 we had an enterprise value of approximately $19 billion. Operations include oil sands projects in northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our upstream assets averaged 484,000 BOE per day in 2018. We also conduct marketing activities and have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of 446,000 gross barrels per day of crude oil feedstock into an average of 470,000 gross barrels per day of refined products in 2018. Our Strategy Our strategy is focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility and give us the flexibility to proceed with opportunities at all points in the price cycle. We aim to evaluate disciplined investment in our portfolio against dividend increases, share repurchases and maintaining the optimal debt level while retaining investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage. We plan to achieve our strategy by leveraging our strategic focus areas. Our Strategic Focus Areas: Oil sands We are committed to maintaining and improving our industry-leading position as a low-cost oil sands operator and the largest in situ producer by leveraging our track record of strong operational performance while demonstrating technical leadership to improve reserves, production and earnings. We will also focus on advancing innovation to unlock future opportunities that maximize value from our vast resource base and improve our environmental footprint. Conventional oil and natural gas We will aim to employ disciplined investment in focused land positions across our conventional oil and natural gas portfolio to generate strong diversified returns, complementing our longer-term oil sands investments with short-cycle development opportunities. Marketing, transportation & refining We will strive to maximize the value from our oil and gas resources through increased participation along the value chain. Our integrated approach to transportation, storage, marketing, upgrading and refining helps optimize margins from each barrel of oil we produce. People We strive to maintain an engaging workplace where people can grow their skills and capabilities to adapt to an ever-changing environment while delivering results for the business. We are focused on upholding trust in the communities where we operate by living up to our values and commitments. Our Operations Oil Sands Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northeast 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. Our project at Telephone Lake is located within the Borealis region of northeastern Alberta. Deep Basin Our Deep Basin operations include liquids rich natural gas, condensate and other NGLs, and light and medium oil assets 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 (collectively, the “Deep Basin Assets”). The Deep Basin Assets were acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) in conjunction with their 50 percent interest in the FCCL Partnership (“FCCL”) on May 17, 2017 (the “Acquisition”). The Deep Basin Assets provide short-cycle development opportunities with high return potential that complement our long-term oil sands development. A portion of the natural gas we produce is used as fuel in our oil sands operations and provides an economic hedge for the natural gas required as a fuel source at our refining operations. 6 | CENOVUS ENERGY Our operations include two refineries located in the U.S. in Illinois and Texas that are jointly owned with (50 percent interest) and operated by Phillips 66, an unrelated U.S. public company. In 2018, the gross crude oil capacity at the Wood River refinery and Borger refinery (the “Refineries”) was approximately 314,000 barrels per day and 146,000 barrels per day, respectively. As a result of consistently strong operating performance, higher utilization rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing capacity, effective January 1, 2019. Crude capacity at the Wood River refinery was re-rated to 333,000 barrels per day, while capacity at the Borger refinery was re-rated to 149,000 barrels per day. 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. Operating Margin Net of Related Capital Investment Year Ended December 31, 2018 ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Refining and Oil Sands Deep Basin Marketing 1,086 887 199 312 211 101 996 208 788 YEAR IN REVIEW In 2018, we delivered on the commitments we made to our shareholders. We demonstrated capital discipline and cost leadership, made significant progress in deleveraging our balance sheet, and strengthened our long-term market access position. Operational performance continued to be strong, with production from continuing operations averaging 483,458 BOE per day, a 32 percent increase from 2017. The Refineries also demonstrated excellent operational performance in 2018, with both Wood River and Borger operating above nameplate capacity in the second half of the year following major planned turnarounds in the first quarter. Crude oil prices continued to be very volatile in 2018, with West Texas Intermediate (“WTI”) reaching nearly US$80 per barrel in October and exiting the year more than US$30 per barrel lower. Overall, WTI prices averaged 27 percent higher than in 2017, while Western Canadian Select (“WCS”) were negatively impacted by takeaway capacity constraints. The differential between WTI and WCS prices averaged US$26.31 per barrel, a 120 percent increase compared with 2017, reaching a record of US$52.00 per barrel in the fourth quarter, leaving the average WCS benchmark price relatively unchanged year over year. Flat WCS prices, increased condensate costs consistent with the rise in WTI benchmark prices, and significant realized risk management losses negatively impacted our financial results (operating margin) from our upstream assets. At the same time, the wide differentials between WTI and WCS as well as WTI and West Texas Sour (“WTS”) crude oil prices provided a feedstock cost advantage at our Refineries increasing year over year financial results (operating margin) from that portion of our business. Our net loss for the year of $2.7 billion reflects the write off of $2.1 billion of exploration and evaluation (“E&E”) costs in the Deep Basin, a loss on the sale of the Cenovus Pipestone Partnership (“CPP”), and an onerous contract provision related to real estate of $629 million following the sublease of a significant portion of excess real estate. We also incurred severance costs related to workforce reductions. In 2018, we: • • • • • • • • Repaid US$876 million of our unsecured notes, reducing net debt to $8.4 billion, driven by Free Funds Flow of $311 million and proceeds from asset divestitures of $1,050 million. In January 2019, we repurchased a further US$324 million of our unsecured notes at a discount; Strengthened our long-term market access position through three-year rail agreements to transport approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the U.S. Gulf Coast, providing a means of mitigating some of the price impact of pipeline congestion; Increased our committed capacity on the Keystone XL Pipeline project by 100,000 barrels per day; Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017; Earned an average companywide Netback from continuing operations, before realized hedging, of $18.51 per BOE, down 11 percent from 2017; Achieved upstream operating margin from continuing operations of $1,398 million compared with $2,394 million in 2017, due in part to realized risk management losses of $1,577 million largely as a result of hedging contracts established in 2017; Achieved nearly $1.0 billion of operating margin from Refining and Marketing due to strong crude utilization rates at both Refineries and the feedstock cost advantage associated with wider crude oil differentials; Re-evaluated our Deep Basin E&E projects in line with our current business plan. As a result, we wrote off previously capitalized E&E costs of $2.1 billion in the fourth quarter as an exploration expense; OVERVIEW OF CENOVUS Refining and Marketing Our operations include two refineries located in the U.S. in Illinois and Texas that are jointly owned with (50 percent interest) and operated by Phillips 66, an unrelated U.S. public company. In 2018, the gross crude oil capacity at the Wood River refinery and Borger refinery (the “Refineries”) was approximately 314,000 barrels per day and 146,000 barrels per day, respectively. As a result of consistently strong operating performance, higher utilization rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing capacity, effective January 1, 2019. Crude capacity at the Wood River refinery was re-rated to 333,000 barrels per day, while capacity at the Borger refinery was re-rated to 149,000 barrels per day. 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. We are committed to maintaining and improving our industry-leading position as a low-cost oil sands operator and the largest in situ producer by leveraging our track record of strong operational performance while demonstrating technical leadership to improve reserves, production and earnings. We will also focus on advancing innovation to unlock future opportunities that maximize value from our vast resource base and improve our environmental YEAR IN REVIEW Operating Margin Net of Related Capital Investment Year Ended December 31, 2018 ($ millions) Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Oil Sands Deep Basin 1,086 887 199 Refining and Marketing 996 208 788 312 211 101 In 2018, we delivered on the commitments we made to our shareholders. We demonstrated capital discipline and cost leadership, made significant progress in deleveraging our balance sheet, and strengthened our long-term market access position. Operational performance continued to be strong, with production from continuing operations averaging 483,458 BOE per day, a 32 percent increase from 2017. The Refineries also demonstrated excellent operational performance in 2018, with both Wood River and Borger operating above nameplate capacity in the second half of the year following major planned turnarounds in the first quarter. Crude oil prices continued to be very volatile in 2018, with West Texas Intermediate (“WTI”) reaching nearly US$80 per barrel in October and exiting the year more than US$30 per barrel lower. Overall, WTI prices averaged 27 percent higher than in 2017, while Western Canadian Select (“WCS”) were negatively impacted by takeaway capacity constraints. The differential between WTI and WCS prices averaged US$26.31 per barrel, a 120 percent increase compared with 2017, reaching a record of US$52.00 per barrel in the fourth quarter, leaving the average WCS benchmark price relatively unchanged year over year. Flat WCS prices, increased condensate costs consistent with the rise in WTI benchmark prices, and significant realized risk management losses negatively impacted our financial results (operating margin) from our upstream assets. At the same time, the wide differentials between WTI and WCS as well as WTI and West Texas Sour (“WTS”) crude oil prices provided a feedstock cost advantage at our Refineries increasing year over year financial results (operating margin) from that portion of our business. Our net loss for the year of $2.7 billion reflects the write off of $2.1 billion of exploration and evaluation (“E&E”) costs in the Deep Basin, a loss on the sale of the Cenovus Pipestone Partnership (“CPP”), and an onerous contract provision related to real estate of $629 million following the sublease of a significant portion of excess real estate. We also incurred severance costs related to workforce reductions. 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, 2018 we had an enterprise value of approximately $19 billion. Operations include oil sands projects in northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our upstream assets averaged 484,000 BOE per day in 2018. We also conduct marketing activities and have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of 446,000 gross barrels per day of crude oil feedstock into an average of 470,000 gross barrels per day of refined products in 2018. Our Strategy Our strategy is focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility and give us the flexibility to proceed with opportunities at all points in the price cycle. We aim to evaluate disciplined investment in our portfolio against dividend increases, share repurchases and maintaining the optimal debt level while retaining investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage. We plan to achieve our strategy by leveraging our strategic focus areas. Our Strategic Focus Areas: Oil sands footprint. Conventional oil and natural gas short-cycle development opportunities. Marketing, transportation & refining from each barrel of oil we produce. People Our Operations Oil Sands northeastern Alberta. Deep Basin We will aim to employ disciplined investment in focused land positions across our conventional oil and natural gas portfolio to generate strong diversified returns, complementing our longer-term oil sands investments with We will strive to maximize the value from our oil and gas resources through increased participation along the value chain. Our integrated approach to transportation, storage, marketing, upgrading and refining helps optimize margins We strive to maintain an engaging workplace where people can grow their skills and capabilities to adapt to an ever-changing environment while delivering results for the business. We are focused on upholding trust in the communities where we operate by living up to our values and commitments. Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northeast 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. Our project at Telephone Lake is located within the Borealis region of Our Deep Basin operations include liquids rich natural gas, condensate and other NGLs, and light and medium oil assets 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 (collectively, the “Deep Basin Assets”). The Deep Basin Assets were acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) in conjunction with their 50 percent interest in the FCCL Partnership (“FCCL”) on May 17, 2017 (the “Acquisition”). The Deep Basin Assets provide short-cycle development opportunities with high return potential that complement our long-term oil sands development. A portion of the natural gas we produce is used as fuel in our oil sands operations and provides an economic hedge for the natural gas required as a fuel source at our refining operations. Repaid US$876 million of our unsecured notes, reducing net debt to $8.4 billion, driven by Free Funds Flow of $311 million and proceeds from asset divestitures of $1,050 million. In January 2019, we repurchased a further US$324 million of our unsecured notes at a discount; Strengthened our long-term market access position through three-year rail agreements to transport approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the U.S. Gulf Coast, providing a means of mitigating some of the price impact of pipeline congestion; Increased our committed capacity on the Keystone XL Pipeline project by 100,000 barrels per day; Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017; Earned an average companywide Netback from continuing operations, before realized hedging, of $18.51 per BOE, down 11 percent from 2017; Achieved upstream operating margin from continuing operations of $1,398 million compared with $2,394 million in 2017, due in part to realized risk management losses of $1,577 million largely as a result of hedging contracts established in 2017; Achieved nearly $1.0 billion of operating margin from Refining and Marketing due to strong crude utilization rates at both Refineries and the feedstock cost advantage associated with wider crude oil differentials; Re-evaluated our Deep Basin E&E projects in line with our current business plan. As a result, we wrote off previously capitalized E&E costs of $2.1 billion in the fourth quarter as an exploration expense; In 2018, we: • • • • • • • • 2018 ANNUAL REPORT | 7 • • • • Recorded a net loss from continuing operations of $2,916 million compared with net earnings of $2,268 million in 2017; Invested $1,363 million of capital compared with $1,661 million in 2017, reflecting our continued focus on capital discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital investment to progress Christina Lake phase G; Achieved payout for royalty purposes at our Christina Lake project upon cumulative project revenues exceeding cumulative project allowable costs, resulting in the royalty calculation now being based on post-payout royalty rates, as discussed in the Oil Sands section of this MD&A; and Reached an agreement to sublease a portion of our Calgary office space that was in excess of our requirements. On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production curtailment for Alberta producers, starting in January 2019, to address the record-high differentials. While our production levels in 2019 will be impacted due to the curtailment, the expected improvement to oil prices is anticipated to have a positive impact on our cash flows. OPERATING RESULTS Upstream Production Volumes Continuing Operations Liquids (barrels per day) Oil Sands Foster Creek Christina Lake Deep Basin Crude Oil NGLs 2018 Percent Change 2017 Percent Change 2016 161,979 201,017 362,996 5,916 26,538 32,454 30 20 24 51 57 56 124,752 167,727 292,479 3,922 16,928 20,850 78 111 95 70,244 79,449 149,693 - - - - - - Liquids Production (barrels per day) 395,450 26 313,329 109 149,693 Natural Gas (MMcf per day) Oil Sands Deep Basin (1) 1 527 528 (90 ) 67 62 10 316 326 (41 ) - 1,818 17 - 17 Production From Continuing Operations (BOE per day) Production From Discontinued Operations (Conventional) (BOE per day) 483,458 32 367,635 141 152,527 294 (100 ) 102,855 (14 ) 118,998 Total Production (BOE per day) 483,752 3 470,490 73 271,525 (1) Includes production used for internal consumption by the Oil Sands segment of 306 MMcf per day for the year ended December 31, 2018 (no internal usage of Deep Basin production in 2017 or 2016). Our upstream operations performed very well as we successfully managed our production rates in response to pipeline capacity constraints and discounted heavy oil prices. Total production from continuing operations increased 32 percent compared with 2017, primarily due to the Acquisition contributing a full year of volumes in 2018. In addition, strong operational performance in the oil sands and increased production from the Deep Basin Assets contributed to higher volumes, partially offset by the divestiture of CPP on September 6, 2018. Production for the year ended December 31, 2018 from our Conventional segment includes the results of our Suffield operations, which were sold on January 5, 2018. All references to our legacy Conventional segment are accounted for as a discontinued operation. Oil and Gas Reserves Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2018 we had total proved reserves of approximately 5.2 billion BOE, in line with 2017, while total proved plus probable reserves decreased two percent to approximately 7 billion BOE. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. 8 | CENOVUS ENERGY 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 page 124. ($/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) 2018 35.74 3.43 6.11 7.68 0.01 18.51 (9.90 ) 8.61 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. Excludes intersegment sales. Our average Netback, excluding realized risk management gains and losses, decreased 11 percent in 2018 due to higher royalties and transportation and blending costs, as well as lower realized sales prices, partially offset by lower operating costs. The strengthening of the Canadian dollar relative to the U.S. dollar compared with 2017 had a negative impact on our sales price of approximately $0.05 per BOE. Both Refineries demonstrated strong operational performance in 2018 and benefited from higher realized crack spreads from improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which created a feedstock cost advantage. Following major planned turnarounds that were substantially completed in the first quarter of 2018, crude utilization rates at both Refineries averaged above nameplate capacity in the second half 2018 446 191 470 97 996 Percent Change 1 (5 ) - 1 67 2017 442 202 470 96 598 Percent Change - (13 ) - (1 ) 73 2016 444 233 471 97 346 (1) (2) Represents 100 percent of the Wood River and Borger refinery operations. Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day. Operating Margin from Refining and Marketing increased 67 percent in 2018 primarily due to wider crude oil price differentials, and a reduction in the cost of Renewable Identification Numbers (“RINs”), partially offset by increased operating costs due to the planned turnarounds at both Refineries in the first quarter of 2018. Further information on the changes in our production volumes, and other items included in our Netbacks and refining results can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements. Refining and Marketing of 2018. Crude Oil Runs (1) (Mbbls/d) Heavy Crude Oil (1) Refined Product (1) (Mbbls/d) Crude Utilization (1) (2) (percent) Operating Margin ($ millions) in 2017; • • • • Invested $1,363 million of capital compared with $1,661 million in 2017, reflecting our continued focus on capital discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital investment to progress Christina Lake phase G; Achieved payout for royalty purposes at our Christina Lake project upon cumulative project revenues exceeding cumulative project allowable costs, resulting in the royalty calculation now being based on post-payout royalty rates, as discussed in the Oil Sands section of this MD&A; and Reached an agreement to sublease a portion of our Calgary office space that was in excess of our requirements. On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production curtailment for Alberta producers, starting in January 2019, to address the record-high differentials. While our production levels in 2019 will be impacted due to the curtailment, the expected improvement to oil prices is anticipated to have a positive impact on our cash flows. OPERATING RESULTS Upstream Production Volumes Continuing Operations Liquids (barrels per day) Oil Sands Foster Creek Christina Lake Deep Basin Crude Oil NGLs Natural Gas (MMcf per day) Oil Sands Deep Basin (1) Production From Continuing Operations (BOE per day) Production From Discontinued Operations (Conventional) (BOE per day) 2018 Percent Change 2017 Percent Change 2016 161,979 201,017 362,996 5,916 26,538 32,454 30 20 24 51 57 56 124,752 167,727 292,479 3,922 16,928 20,850 78 111 95 70,244 79,449 149,693 - - - 1 527 528 (90 ) 67 62 10 316 326 (41 ) - 1,818 483,458 32 367,635 141 152,527 - - - 17 - 17 Liquids Production (barrels per day) 395,450 26 313,329 109 149,693 Total Production (BOE per day) 483,752 3 470,490 73 271,525 (1) Includes production used for internal consumption by the Oil Sands segment of 306 MMcf per day for the year ended December 31, 2018 (no internal usage of Deep Basin production in 2017 or 2016). Our upstream operations performed very well as we successfully managed our production rates in response to pipeline capacity constraints and discounted heavy oil prices. Total production from continuing operations increased 32 percent compared with 2017, primarily due to the Acquisition contributing a full year of volumes in 2018. In addition, strong operational performance in the oil sands and increased production from the Deep Basin Assets contributed to higher volumes, partially offset by the divestiture of CPP on September 6, 2018. Production for the year ended December 31, 2018 from our Conventional segment includes the results of our Suffield operations, which were sold on January 5, 2018. All references to our legacy Conventional segment are accounted for as a discontinued operation. Oil and Gas Reserves Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2018 we had total proved reserves of approximately 5.2 billion BOE, in line with 2017, while total proved plus probable reserves decreased two percent to approximately 7 billion BOE. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. Recorded a net loss from continuing operations of $2,916 million compared with net earnings of $2,268 million Netbacks From Continuing Operations Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see page 124. ($/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) 2018 35.74 3.43 6.11 7.68 0.01 18.51 (9.90 ) 8.61 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. Excludes intersegment sales. Our average Netback, excluding realized risk management gains and losses, decreased 11 percent in 2018 due to higher royalties and transportation and blending costs, as well as lower realized sales prices, partially offset by lower operating costs. The strengthening of the Canadian dollar relative to the U.S. dollar compared with 2017 had a negative impact on our sales price of approximately $0.05 per BOE. Refining and Marketing Both Refineries demonstrated strong operational performance in 2018 and benefited from higher realized crack spreads from improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which created a feedstock cost advantage. Following major planned turnarounds that were substantially completed in the first quarter of 2018, crude utilization rates at both Refineries averaged above nameplate capacity in the second half of 2018. 294 (100 ) 102,855 (14 ) 118,998 (1) (2) Heavy Crude Oil (1) Crude Oil Runs (1) (Mbbls/d) Refined Product (1) (Mbbls/d) Crude Utilization (1) (2) (percent) Operating Margin ($ millions) 446 191 470 97 996 Represents 100 percent of the Wood River and Borger refinery operations. Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day. 1 (5 ) - 1 67 2018 Percent Change 2017 442 202 470 96 598 Percent Change - (13 ) - (1 ) 73 2016 444 233 471 97 346 Operating Margin from Refining and Marketing increased 67 percent in 2018 primarily due to wider crude oil price differentials, and a reduction in the cost of Renewable Identification Numbers (“RINs”), partially offset by increased operating costs due to the planned turnarounds at both Refineries in the first quarter of 2018. Further information on the changes in our production volumes, and other 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. 2018 ANNUAL REPORT | 9 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. Selected Benchmark Prices and Exchange Rates (1) (US$/bbl, unless otherwise indicated) Q4 2018 Q4 2017 2018 Percent Change 2017 2016 Brent Average End of Period WTI Average End of Period Average Differential Brent-WTI WCS Average Average (C$/bbl) End of Period Average Differential WTI-WCS WTS Average End of Period Average Differential WTI-WTS Condensate (C5 @ Edmonton) Average Average (C$/bbl) Average Differential WTI-Condensate (Premium)/Discount Average Differential WCS-Condensate (Premium)/Discount Mixed Sweet Blend ("MSW" @ Edmonton) Average Average (C$/bbl) End of Period Average Refined Product Prices 68.08 53.80 61.54 66.87 71.53 53.80 30 (20 ) 54.82 66.87 45.04 56.82 58.81 45.41 9.27 55.40 60.42 6.14 64.77 45.41 6.76 27 (25 ) 75 50.95 60.42 3.87 19.39 25.60 30.69 39.42 43.14 54.84 34.93 12.26 38.46 49.81 30.69 26.31 (1 ) (1 ) (12 ) 120 38.97 50.56 34.93 11.98 52.38 38.53 6.43 54.93 60.47 0.47 57.24 38.53 7.53 15 (36 ) 624 49.91 60.47 1.04 43.32 53.72 1.72 29.48 39.05 38.81 13.84 42.36 52.27 0.96 45.28 59.74 57.97 73.66 61.00 79.02 18 18 51.57 66.89 42.47 56.25 13.53 (2.57 ) 3.77 (708 ) (0.62 ) 0.85 (25.89 ) (14.83 ) (22.54 ) 79 (12.60 ) (12.99 ) 32.51 42.89 44.19 54.26 68.95 53.03 53.65 69.49 44.19 11 10 (17 ) 48.49 62.89 53.03 40.11 53.13 51.26 Chicago Regular Unleaded Gasoline ("RUL") Chicago Ultra-low Sulphur Diesel ("ULSD") 66.65 84.25 74.36 80.58 77.96 86.75 16 26 66.95 69.09 56.24 56.33 Refining Margin: Average 3-2-1 Crack Spreads (2) Chicago Group 3 Average Natural Gas Prices AECO (C$/Mcf) (3) NYMEX (US$/Mcf) Basis Differential NYMEX-AECO (US$/Mcf) Foreign Exchange Rate (US$ per C$1) Average End of Period 13.43 14.57 21.09 18.77 15.97 16.74 (5 ) 1 16.77 16.61 13.07 12.27 1.90 3.64 2.19 1.96 2.93 1.40 1.53 3.09 1.90 (37 ) (1 ) 51 2.43 3.11 1.26 2.09 2.46 0.89 0.758 0.733 0.787 0.797 0.772 0.733 - (8 ) 0.771 0.797 0.755 0.745 (1) (2) (3) 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 and Reportable Segments sections of this MD&A. 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 monthly index. Crude Oil Benchmarks In 2018, the annual average Brent and WTI crude oil benchmark prices improved, while heavy oil differentials widened significantly in response to market access constraints and increasing heavy oil production in Alberta. Brent and WTI crude oil prices averaged 30 percent and 27 percent higher, respectively, compared with 2017, while WCS prices decreased one percent. Continued uncertainty over Venezuelan supply and the possibility of the U.S. enforcing sanctions on Iran supported improved global crude oil benchmark pricing through the majority of 2018. Reduced inventory levels from compliance with production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) and Russia have supported global oil prices. In June 2018, OPEC agreed to scale back over-compliance with 10 | CENOVUS ENERGY production cuts by its members, which introduced the possibility of a modest increase in production and renewed concerns around oversupply. In addition, a reduced global demand outlook for 2019 and broader market weakness weighed on crude oil prices ahead of the December 2018 OPEC meeting, where OPEC once again agreed to cut production in an attempt to reduce inventory levels and support crude prices. WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In 2018, the Brent-WTI differential widened significantly compared with 2017. WTI prices were limited by production from the Permian Basin exceeding available pipeline capacity out of west Texas, leading to increased volumes moving from Cushing, Oklahoma to the U.S. Gulf Coast on pipelines that were already nearing capacity. WTI prices were also negatively impacted in the second half of 2018 due to the start of seasonal refining maintenance in the Midwest and Midcontinent regions which reduced demand for crude oil. WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential was significantly wider in 2018 compared with 2017. Increased production resulted in pipeline apportionments while the inability to transport additional volumes by rail in the short term and the lack of clarity surrounding future pipelines continued to put downward pressure on WCS benchmark prices. On December 2, 2018, the Government of Alberta announced temporary mandatory oil production curtailments for Alberta producers to address the record-high differentials, commencing January 2019. In response to the Government of Alberta’s action, the differential between WTI and WCS has narrowed substantially thus far in 2019. The level of curtailment necessary is expected to drop over the course of 2019 as storage levels normalize, and as increased crude-by-rail capacity and the potential start-up of Enbridge Inc.’s Line 3 Replacement Project later this year help alleviate takeaway capacity constraints. Historical Crude Oil Benchmark Prices 75 65 55 45 35 25 15 ) l b b / $ S U e g a r e v a ( Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2018 2017 WTI WCS WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI crude oil, and is a primary component of the input feedstock at the Borger refinery. The differential between WTI and WTS benchmark prices widened significantly in 2018, due primarily to pipeline congestion out of west Texas, as discussed above. Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent volumes as a percentage of total blended volumes, range from approximately 25 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. Condensate benchmark prices averaged 18 percent higher in 2018, consistent with the rise in light oil prices over the same periods. The average WTI-condensate differential changed by US$4.39 per barrel, with condensate being sold at a discount to WTI in 2018 as compared with being sold at a premium in 2017. The condensate price discount relative to WTI in 2018 was due to high domestic inventories, in addition to increasing domestic supply combined with higher than anticipated imports. MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production, comparable to the crude oil produced by our Deep Basin Assets. The average MSW benchmark price improved in 2018 compared with 2017, consistent with the general increase in average crude oil prices. Refining Benchmarks The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis. COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results. Selected Benchmark Prices and Exchange Rates (1) (US$/bbl, unless otherwise indicated) Q4 2018 Q4 2017 2018 Change 2017 2016 Percent Brent Average End of Period WTI Average End of Period WCS Average Average (C$/bbl) End of Period WTS Average End of Period Average Differential Brent-WTI Average Differential WTI-WCS Average Differential WTI-WTS Condensate (C5 @ Edmonton) Average Average (C$/bbl) Average Differential WTI-Condensate (Premium)/Discount Average Differential WCS-Condensate (Premium)/Discount Mixed Sweet Blend ("MSW" @ Edmonton) Average Average (C$/bbl) End of Period Average Refined Product Prices Chicago Regular Unleaded Gasoline ("RUL") Chicago Ultra-low Sulphur Diesel ("ULSD") Refining Margin: Average 3-2-1 Crack Spreads (2) Chicago Group 3 Average Natural Gas Prices AECO (C$/Mcf) (3) NYMEX (US$/Mcf) Basis Differential NYMEX-AECO (US$/Mcf) Foreign Exchange Rate (US$ per C$1) Average End of Period 68.08 53.80 61.54 66.87 71.53 53.80 30 (20 ) 54.82 66.87 45.04 56.82 58.81 45.41 9.27 55.40 60.42 6.14 64.77 45.41 6.76 27 (25 ) 75 50.95 60.42 3.87 19.39 25.60 30.69 39.42 43.14 54.84 34.93 12.26 38.46 49.81 30.69 26.31 (1 ) (1 ) (12 ) 120 38.97 50.56 34.93 11.98 52.38 38.53 6.43 54.93 60.47 0.47 57.24 38.53 7.53 15 (36 ) 624 49.91 60.47 1.04 43.32 53.72 1.72 29.48 39.05 38.81 13.84 42.36 52.27 0.96 45.28 59.74 57.97 73.66 61.00 79.02 18 18 51.57 66.89 42.47 56.25 13.53 (2.57 ) 3.77 (708 ) (0.62 ) 0.85 (25.89 ) (14.83 ) (22.54 ) 79 (12.60 ) (12.99 ) 32.51 42.89 44.19 54.26 68.95 53.03 53.65 69.49 44.19 11 10 (17 ) 48.49 62.89 53.03 40.11 53.13 51.26 66.65 84.25 74.36 80.58 77.96 86.75 16 26 66.95 69.09 56.24 56.33 13.43 14.57 21.09 18.77 15.97 16.74 (5 ) 1 16.77 16.61 13.07 12.27 1.90 3.64 2.19 1.96 2.93 1.40 1.53 3.09 1.90 (37 ) (1 ) 51 2.43 3.11 1.26 2.09 2.46 0.89 0.758 0.733 0.787 0.797 0.772 0.733 - (8 ) 0.771 0.797 0.755 0.745 (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 and Reportable Segments sections of this MD&A. 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 monthly index. (2) (3) Crude Oil Benchmarks In 2018, the annual average Brent and WTI crude oil benchmark prices improved, while heavy oil differentials widened significantly in response to market access constraints and increasing heavy oil production in Alberta. Brent and WTI crude oil prices averaged 30 percent and 27 percent higher, respectively, compared with 2017, while WCS prices decreased one percent. Continued uncertainty over Venezuelan supply and the possibility of the U.S. enforcing sanctions on Iran supported improved global crude oil benchmark pricing through the majority of 2018. Reduced inventory levels from compliance with production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) and Russia have supported global oil prices. In June 2018, OPEC agreed to scale back over-compliance with production cuts by its members, which introduced the possibility of a modest increase in production and renewed concerns around oversupply. In addition, a reduced global demand outlook for 2019 and broader market weakness weighed on crude oil prices ahead of the December 2018 OPEC meeting, where OPEC once again agreed to cut production in an attempt to reduce inventory levels and support crude prices. WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In 2018, the Brent-WTI differential widened significantly compared with 2017. WTI prices were limited by production from the Permian Basin exceeding available pipeline capacity out of west Texas, leading to increased volumes moving from Cushing, Oklahoma to the U.S. Gulf Coast on pipelines that were already nearing capacity. WTI prices were also negatively impacted in the second half of 2018 due to the start of seasonal refining maintenance in the Midwest and Midcontinent regions which reduced demand for crude oil. WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential was significantly wider in 2018 compared with 2017. Increased production resulted in pipeline apportionments while the inability to transport additional volumes by rail in the short term and the lack of clarity surrounding future pipelines continued to put downward pressure on WCS benchmark prices. On December 2, 2018, the Government of Alberta announced temporary mandatory oil production curtailments for Alberta producers to address the record-high differentials, commencing January 2019. In response to the Government of Alberta’s action, the differential between WTI and WCS has narrowed substantially thus far in 2019. The level of curtailment necessary is expected to drop over the course of 2019 as storage levels normalize, and as increased crude-by-rail capacity and the potential start-up of Enbridge Inc.’s Line 3 Replacement Project later this year help alleviate takeaway capacity constraints. Historical Crude Oil Benchmark Prices 75 65 55 45 35 25 15 ) l b b / $ S U e g a r e v a ( Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 WTI WCS 2018 WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI crude oil, and is a primary component of the input feedstock at the Borger refinery. The differential between WTI and WTS benchmark prices widened significantly in 2018, due primarily to pipeline congestion out of west Texas, as discussed above. Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent volumes as a percentage of total blended volumes, range from approximately 25 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. Condensate benchmark prices averaged 18 percent higher in 2018, consistent with the rise in light oil prices over the same periods. The average WTI-condensate differential changed by US$4.39 per barrel, with condensate being sold at a discount to WTI in 2018 as compared with being sold at a premium in 2017. The condensate price discount relative to WTI in 2018 was due to high domestic inventories, in addition to increasing domestic supply combined with higher than anticipated imports. 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 2018 compared with 2017, consistent with the general increase in average crude oil 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 market crack spread. The 3-2-1 market 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. 2018 ANNUAL REPORT | 11 Average Chicago refined product prices increased in 2018 primarily due to higher global crude oil prices. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by international prices, the strength of refining crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and WTI benchmark prices. In 2018, the Chicago 3-2-1 crack spread weakened five percent, while the Group 3 crack spread remained relatively unchanged from 2017. 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 Chicago 3-2-1 Crack Spread FINANCIAL RESULTS Selected Consolidated Financial Results In 2018, the primary drivers of our financial results include the impact of the Acquisition, rising light oil benchmark prices, higher condensate prices, significantly wider light-heavy crude oil price differentials and realized risk management losses. The following key performance measures are discussed in more detail within this MD&A. 2018 20,844 Percent Change 2017 Percent Change 22 17,043 55 2018 2017 ) l b b / $ S U e g a r e v a ( 90 80 70 60 50 40 30 2016 ) l b b / $ S U e g a r e v a ( 30 25 20 15 10 5 2018 2017 2016 Jan Q1 Feb Mar Apr May Q2 June Jul Aug Q3 Sep Oct Q4 Nov Dec Jan Q1 Q1 Feb Mar Apr Q2 Q2 May June Jul Q3 Q3 Aug Sep Oct Q4 Q4 Nov Dec Natural Gas Benchmarks Average AECO prices weakened during 2018 due to higher natural gas supply in Alberta and constrained export capabilities. Average NYMEX prices also decreased slightly compared with 2017 due to continued supply growth from the development of U.S. shale gas and natural gas associated with crude oil plays. Foreign Exchange Benchmark Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, 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, there is a positive impact on our reported results. 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 2018, the Canadian dollar strengthened slightly relative to the U.S. dollar on average, compared with 2017, resulting in a negative impact of approximately $27 million on our revenues in 2018, excluding our Conventional segment. The Canadian dollar as at December 31, 2018 compared with December 31, 2017 was weaker relative to the U.S. dollar, resulting in $602 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt. 12 | CENOVUS ENERGY ($ 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 ($) (3) Total Operating Earnings (Loss) Per Share ($) (3) Net Earnings (Loss) From Continuing Operations Per Share ($) (3) Total Net Earnings (Loss) Per Share ($) (3) Total Assets Capital Investment (5) From Continuing Operations Total Capital Investment Dividends Cash Dividends Per Share ($) Total Long-Term Financial Liabilities (4) 2,394 2,431 2,118 2,154 1,637 1,674 (2,755 ) (2.24 ) (2,729 ) (2.22 ) (2,916 ) (2.37 ) (2,669 ) (2.17 ) 35,174 8,602 (20 ) (30 ) (19 ) (30 ) (33 ) (43 ) (8,003 ) (7,367 ) (2,266 ) (2,118 ) (229 ) (215 ) (179 ) (171 ) (14 ) (11 ) 2,992 3,483 2,611 3,059 2,447 2,914 (34 ) (0.03 ) 126 0.11 2,268 2.06 3,366 3.05 40,933 9,717 1,363 1,363 (6 ) 1,455 (18 ) 1,661 245 0.20 9 - 225 0.20 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 0.20 145 97 513 255 154 105 88 91 (133 ) (124 ) (594 ) (475 ) (718 ) (569 ) 62 52 70 62 36 - (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. Represented on a basic and diluted per share basis. 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. ) l b b / $ S U e g a r e v a ( 30 25 20 15 10 5 ) l b b / $ S U e g a r e v a ( 90 80 70 60 50 40 30 Average Chicago refined product prices increased in 2018 primarily due to higher global crude oil prices. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by international prices, the strength of refining crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and WTI benchmark prices. In 2018, the Chicago 3-2-1 crack spread weakened five percent, while the Group 3 crack spread remained relatively unchanged from 2017. 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 Chicago 3-2-1 Crack Spread 2018 2017 2018 2017 2016 2016 Jan Q1 Feb Mar Apr Q2 May June Jul Aug Q3 Sep Oct Q4 Nov Dec Jan Q1 Q1 Feb Mar Apr Q2 Q2 May June Jul Q3 Q3 Aug Sep Oct Q4 Q4 Nov Dec Natural Gas Benchmarks Average AECO prices weakened during 2018 due to higher natural gas supply in Alberta and constrained export capabilities. Average NYMEX prices also decreased slightly compared with 2017 due to continued supply growth from the development of U.S. shale gas and natural gas associated with crude oil plays. Foreign Exchange Benchmark Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, 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, there is a positive impact on our reported results. 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 2018, the Canadian dollar strengthened slightly relative to the U.S. dollar on average, compared with 2017, resulting in a negative impact of approximately $27 million on our revenues in 2018, excluding our Conventional segment. The Canadian dollar as at December 31, 2018 compared with December 31, 2017 was weaker relative to the U.S. dollar, resulting in $602 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt. FINANCIAL RESULTS Selected Consolidated Financial Results In 2018, the primary drivers of our financial results include the impact of the Acquisition, rising light oil benchmark prices, higher condensate prices, significantly wider light-heavy crude oil price differentials and realized risk management losses. The following key performance measures are discussed in more detail within this MD&A. ($ 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 ($) (3) Total Operating Earnings (Loss) Per Share ($) (3) Net Earnings (Loss) From Continuing Operations Per Share ($) (3) Total Net Earnings (Loss) Per Share ($) (3) Total Assets Total Long-Term Financial Liabilities (4) Capital Investment (5) From Continuing Operations Total Capital Investment Dividends 2018 20,844 Percent Change 22 2017 17,043 Percent Change 55 2,394 2,431 2,118 2,154 1,637 1,674 (2,755 ) (2.24 ) (2,729 ) (2.22 ) (2,916 ) (2.37 ) (2,669 ) (2.17 ) 35,174 8,602 (20 ) (30 ) (19 ) (30 ) (33 ) (43 ) (8,003 ) (7,367 ) (2,266 ) (2,118 ) (229 ) (215 ) (179 ) (171 ) (14 ) (11 ) 2,992 3,483 2,611 3,059 2,447 2,914 (34 ) (0.03 ) 126 0.11 2,268 2.06 3,366 3.05 40,933 9,717 145 97 513 255 154 105 88 91 (133 ) (124 ) (594 ) (475 ) (718 ) (569 ) 62 52 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 1,363 1,363 (6 ) 1,455 (18 ) 1,661 70 62 855 1,026 Cash Dividends Per Share ($) 225 0.20 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. Represented on a basic and diluted per share basis. 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. 245 0.20 36 - 9 - 0.20 166 (1) (2) (3) (4) (5) 2018 ANNUAL REPORT | 13 Operating Margin From Continuing Operations Variance 1,580 2,992 ) s n o i l l i m $ ( 537 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 1,270 398 274 256 239 2,394 Year Ended December 31, 2017 Upstream Price Upstream Volumes Upstream Realized Risk Royalties Upstream Operating Refining and Marketing Other (1) Management Expenses Operating Margin Year Ended December 31, 2018 (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 Cash From Operating Activities (1) ($ millions) (Add) Deduct: Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (1) 2018 2,154 (72 ) 552 1,674 2017 3,059 (107 ) 252 2,914 2016 861 (91 ) (471 ) 1,423 (1) Includes results from our Conventional segment, which has been classified as a discontinued operation. Cash From Operating Activities and Adjusted Funds Flow were lower compared with 2017 due to lower Operating Margin, as discussed above, a lower current tax recovery, and higher general and administrative costs primarily due to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of $56 million related to the Acquisition. These decreases were partially offset by changes in non-cash working capital in 2018 which was primarily due to a decrease in accounts receivable and inventory, partially offset by a decrease in accounts payable. In 2017, the change in non-cash working capital was primarily due to a decrease in accounts receivable and inventory, partially offset by higher income tax receivable and a decrease in accounts payable. Revenues ($ millions) Revenues, Comparative Year Increase (Decrease) due to: Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Revenues, End of Year 2018 vs. 2017 17,043 2017 vs. 2016 11,006 2,421 318 1,331 (269 ) 20,844 4,212 514 1,413 (102 ) 17,043 Upstream revenues increased over 2017 due to incremental sales volumes, primarily due to the Acquisition, partially offset by lower realized pricing and higher royalties. Refining and Marketing revenues increased 14 percent in 2018 primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group decreased in 2018 compared with 2017 due to a decline in crude oil and natural gas volumes sold, as well as lower natural gas prices, partially offset by higher crude oil prices. Corporate and Eliminations revenues relate to sales of natural gas or crude oil and operating revenue 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. 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 2018 21,568 2017 17,498 2016 11,359 9,261 5,969 2,367 1 1,576 2,394 37 2,431 8,476 3,760 1,956 1 313 2,992 491 3,483 7,325 1,721 1,243 - (153 ) 1,223 544 1,767 Operating Margin From Continuing Operations by Segment Operating Margin continuing operations decreased in 2018 compared with 2017 primarily due to: • from 2,500 2,000 2,187 A rise in transportation and blending expenses primarily due to the Acquisition resulting in increased condensate volumes required for blending our increased oil sands production, as well as higher condensate benchmark prices; Realized risk management $1,576 million (2017 – losses of $313 million); A decrease in our average liquids sales price; Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), higher sales volumes, as well as the Christina Lake project reaching payout in the third quarter of 2018; and An increase in upstream operating expenses primarily due to the Acquisition. losses of Oil Sands 1,086 1,000 1,500 m $ ( 877 ) s n o 500 i l l i 0 312 • • • • 996 598 346 207 - Deep Basin Refining and Marketing 2018 2017 2016 These decreases in Operating Margin were partially offset by: • • A rise in our liquids and natural gas sales volumes as a result of the Acquisition; and Higher Operating Margin from our Refining and Marketing segment due to wider crude oil differentials. 14 | CENOVUS ENERGY 14 | CENOVUS ENERGY Revenues ($ millions) Oil Sands Deep Basin Revenues, Comparative Year Increase (Decrease) due to: Refining and Marketing Corporate and Eliminations Revenues, End of Year 2018 vs. 2017 17,043 2017 vs. 2016 11,006 2,421 318 1,331 (269 ) 4,212 514 1,413 (102 ) 20,844 17,043 Upstream revenues increased over 2017 due to incremental sales volumes, primarily due to the Acquisition, partially offset by lower realized pricing and higher royalties. Refining and Marketing revenues increased 14 percent in 2018 primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group decreased in 2018 compared with 2017 due to a decline in crude oil and natural gas volumes sold, as well as lower natural gas prices, partially offset by higher crude oil Corporate and Eliminations revenues relate to sales of natural gas or crude oil and operating revenue 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. 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 Operating Margin from continuing operations decreased in 2018 compared with 2017 primarily due A rise in transportation and blending expenses primarily due to the Acquisition resulting in increased condensate volumes required for blending our increased oil sands production, as well as higher condensate benchmark prices; Realized risk management losses of $1,576 million (2017 – losses of $313 million); A decrease in our average liquids sales price; Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), higher sales volumes, as well as the Christina Lake project reaching payout in the third quarter of 2018; and ) s n o i l l i m $ ( 2,500 2,000 1,500 1,000 500 0 to: • • • • • • • 2018 2017 21,568 17,498 2016 11,359 9,261 5,969 2,367 1 1,576 2,394 37 2,431 8,476 3,760 1,956 1 313 2,992 491 3,483 7,325 1,721 1,243 - (153 ) 1,223 544 1,767 Operating Margin From Continuing Operations by Segment 2,187 1,086 877 996 598 346 Oil Sands Deep Basin Refining and Marketing 312 207 - 2018 2017 2016 An increase in upstream operating expenses primarily due to the Acquisition. These decreases in Operating Margin were partially offset by: A rise in our liquids and natural gas sales volumes as a result of the Acquisition; and Higher Operating Margin from our Refining and Marketing segment due to wider crude oil differentials. Operating Margin From Continuing Operations Variance ) s n o i l l i m $ ( 1,580 2,992 537 1,270 398 274 256 239 2,394 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 Year Ended December 31, 2017 Upstream Price Upstream Volumes Upstream Realized Risk Management Royalties Upstream Operating Expenses Refining and Marketing Operating Margin Other (1) Year Ended December 31, 2018 (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) 2018 2,154 (72 ) 552 1,674 2017 3,059 (107 ) 252 2,914 2016 861 (91 ) (471 ) 1,423 (1) Includes results from our Conventional segment, which has been classified as a discontinued operation. Cash From Operating Activities and Adjusted Funds Flow were lower compared with 2017 due to lower Operating Margin, as discussed above, a lower current tax recovery, and higher general and administrative costs primarily due to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of $56 million related to the Acquisition. These decreases were partially offset by changes in non-cash working capital in 2018 which was primarily due to a decrease in accounts receivable and inventory, partially offset by a decrease in accounts payable. In 2017, the change in non-cash working capital was primarily due to a decrease in accounts receivable and inventory, partially offset by higher income tax receivable and a decrease in accounts payable. 2018 ANNUAL REPORT | 15 Operating Earnings (Loss) Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis. ($ 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) 2018 (3,926 ) 2017 2,216 (1,249 ) 593 - 795 (3,787 ) (1,032 ) (2,755 ) 26 (2,729 ) 729 (651 ) (2,555 ) 1 (260 ) (226 ) (34 ) 160 126 2016 (802 ) 554 (196 ) - 6 (438 ) (147 ) (291 ) (86 ) (377 ) (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. In 2018, Operating Earnings decreased primarily due to lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above, exploration expense of $2,123 million compared with $888 million in 2017, a non-cash provision of $629 million for onerous contracts related to office space, increased depreciation, depletion and amortization (“DD&A”), and an unrealized foreign exchange loss of $47 million on operating items compared with gains of $192 million in 2017. Net Earnings (Loss) ($ 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, End of Year 2018 vs. 2017 2,268 2017 vs. 2016 (459 ) (598 ) 1,769 1,978 (1,506 ) (2,555 ) (188 ) (794 ) (951 ) (293 ) (1,235 ) 958 (2,916 ) (175 ) 668 2,555 138 5 (149 ) (907 ) (886 ) (291 ) 2,268 (1) Includes Corporate and Eliminations realized risk management (gains) losses, general and administrative, onerous contract provisions, 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. In 2018, we incurred a net loss of $2,916 million from continuing operations, a significant decrease from 2017, due to: • • • • Lower Operating Earnings, as discussed above; An after-tax revaluation gain of $1.9 billion on our pre-existing interest in FCCL recognized in 2017; Non-operating foreign exchange losses of $593 million compared with gains of $651 million in 2017; and A before-tax loss of $797 million ($557 million after-tax) on the divestiture of CPP. These decreases to our Net Earnings (Loss) from continuing operations in 2018 were partially offset by unrealized risk management gains of $1,249 million compared with losses of $729 million in 2017, and an income tax recovery of $1,010 million compared with a recovery of $52 million in 2017. 16 | CENOVUS ENERGY Net Earnings from discontinued operations for the year ended December 31, 2018 was $247 million (2017 – $1,098 million). Our 2018 results include an after-tax gain of $220 million on the divestiture of the Suffield assets in the first quarter of 2018. Our 2017 results include an after-tax gain of $938 million on the divestiture of the Conventional segment assets. Total Capital Investment ($ millions) Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Capital Investment - Continuing Operations Conventional (Discontinued Operations) Total Capital Investment (1) (1) Includes expenditures on PP&E, E&E assets and assets held for sale. 2018 2017 887 211 208 57 1,363 - 1,363 973 225 180 77 1,455 206 1,661 2016 604 - 220 31 855 171 1,026 Capital investment in continuing operations decreased compared with 2017, reflecting our continued focus on capital discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital investment to progress Christina Lake phase G, partially offset by the 2017 results not reflecting a full year of operations following the Acquisition on May 17, 2017. In 2018, Oil Sands capital investment focused on sustaining capital related to existing production; stratigraphic test wells to determine pad placement for sustaining wells; and the Christina Lake phase G expansion. The majority of our Deep Basin capital program was carried out in the first three months of 2018 and focused on all three operating areas, including the drilling of 15 net horizontal production wells targeting liquids rich natural gas, as well as capital invested in completions, facilities and infrastructure to support production. Refining and Marketing capital investment increased in 2018 due to increased capital maintenance and reliability work compared with the same periods in 2017. Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A. Capital Investment Decisions opportunities. We continue to focus on deleveraging our balance sheet. In addition to our commitment to reduce our debt, we are looking for opportunities to streamline our asset portfolio and are actively identifying further cost reduction Deleveraging is a priority above growth and shareholder returns until we get to $7 billion of net debt. Once our balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner: • • • First, to sustaining and maintenance capital for our existing business operations; Second, to paying our current dividend as part of providing strong total shareholder return; and Third, for incremental returns to shareholders, further deleveraging, and growth or discretionary capital. Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information. ($ millions) Adjusted Funds Flow (1) Total Capital Investment (1) Free Funds Flow (1) (2) Cash Dividends 2018 1,674 1,363 311 245 66 2017 2,914 1,661 1,253 225 1,028 2016 1,423 1,026 397 166 231 (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 2019 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) 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 Continuing Operations Operating Earnings (Loss) From Discontinued Operations Total Operating Earnings (Loss) 2018 (3,926 ) 2017 2,216 (1,249 ) 593 - 795 (3,787 ) (1,032 ) (2,755 ) 26 (2,729 ) 729 (651 ) (2,555 ) 1 (260 ) (226 ) (34 ) 160 126 2016 (802 ) 554 (196 ) - 6 (438 ) (147 ) (291 ) (86 ) (377 ) 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. In 2018, Operating Earnings decreased primarily due to lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above, exploration expense of $2,123 million compared with $888 million in 2017, a non-cash provision of $629 million for onerous contracts related to office space, increased depreciation, depletion and amortization (“DD&A”), and an unrealized foreign exchange loss of $47 million on operating items compared with Net Earnings (Loss) From Continuing Operations, Comparative Year gains of $192 million in 2017. Net Earnings (Loss) ($ 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) 2018 vs. 2017 2,268 2017 vs. 2016 (459 ) (598 ) 1,769 1,978 (1,506 ) (2,555 ) (188 ) (794 ) (951 ) (293 ) (1,235 ) 958 (2,916 ) (175 ) 668 2,555 138 5 (149 ) (907 ) (886 ) (291 ) 2,268 Net Earnings (Loss) From Continuing Operations, End of Year (1) Includes Corporate and Eliminations realized risk management (gains) losses, general and administrative, onerous contract provisions, 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. In 2018, we incurred a net loss of $2,916 million from continuing operations, a significant decrease from 2017, due to: • • • • Lower Operating Earnings, as discussed above; An after-tax revaluation gain of $1.9 billion on our pre-existing interest in FCCL recognized in 2017; Non-operating foreign exchange losses of $593 million compared with gains of $651 million in 2017; and A before-tax loss of $797 million ($557 million after-tax) on the divestiture of CPP. These decreases to our Net Earnings (Loss) from continuing operations in 2018 were partially offset by unrealized risk management gains of $1,249 million compared with losses of $729 million in 2017, and an income tax recovery of $1,010 million compared with a recovery of $52 million in 2017. Net Earnings from discontinued operations for the year ended December 31, 2018 was $247 million (2017 – $1,098 million). Our 2018 results include an after-tax gain of $220 million on the divestiture of the Suffield assets in the first quarter of 2018. Our 2017 results include an after-tax gain of $938 million on the divestiture of the Conventional segment assets. Total Capital Investment ($ millions) Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Capital Investment - Continuing Operations Conventional (Discontinued Operations) Total Capital Investment (1) (1) Includes expenditures on PP&E, E&E assets and assets held for sale. 2018 887 211 208 57 1,363 - 1,363 2017 973 225 180 77 1,455 206 1,661 2016 604 - 220 31 855 171 1,026 Capital investment in continuing operations decreased compared with 2017, reflecting our continued focus on capital discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital investment to progress Christina Lake phase G, partially offset by the 2017 results not reflecting a full year of operations following the Acquisition on May 17, 2017. In 2018, Oil Sands capital investment focused on sustaining capital related to existing production; stratigraphic test wells to determine pad placement for sustaining wells; and the Christina Lake phase G expansion. The majority of our Deep Basin capital program was carried out in the first three months of 2018 and focused on all three operating areas, including the drilling of 15 net horizontal production wells targeting liquids rich natural gas, as well as capital invested in completions, facilities and infrastructure to support production. Refining and Marketing capital investment increased in 2018 due to increased capital maintenance and reliability work compared with the same periods in 2017. Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A. Capital Investment Decisions We continue to focus on deleveraging our balance sheet. In addition to our commitment to reduce our debt, we are looking for opportunities to streamline our asset portfolio and are actively identifying further cost reduction opportunities. Deleveraging is a priority above growth and shareholder returns until we get to $7 billion of net debt. Once our balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner: • • • First, to sustaining and maintenance capital for our existing business operations; Second, to paying our current dividend as part of providing strong total shareholder return; and Third, for incremental returns to shareholders, further deleveraging, and growth or discretionary capital. Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information. ($ millions) Adjusted Funds Flow (1) Total Capital Investment (1) Free Funds Flow (1) (2) Cash Dividends 2018 1,674 1,363 311 245 66 2017 2,914 1,661 1,253 225 1,028 2016 1,423 1,026 397 166 231 (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 2019 to be funded from our internally generated cash flows and our cash balance on hand. 2018 ANNUAL REPORT | 17 REPORTABLE SEGMENTS Our reportable segments are as follows: includes Oil Sands, which the development and production of bitumen 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 2.8 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. These assets were acquired on May 17, 2017. Refining and Marketing, which is responsible for into transporting, selling and refining crude oil 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 and segment transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. Cenovus’s marketing coordinates 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 include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices. In 2017, Cenovus announced its intention to divest of its Conventional segment that included its heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of operations have been reported as discontinued operations. As at January 5, 2018, all of the Conventional segment assets were sold. Refer to the Discontinued Operations section of this MD&A for more information. Revenues by Reportable Segment ($ millions) Oil Sands (1) Deep Basin (1) Refining and Marketing Corporate and Eliminations 2018 9,553 832 11,183 (724 ) 20,844 2017 7,132 514 9,852 (455 ) 17,043 2016 2,920 - 8,439 (353 ) 11,006 (1) Our 2017 results include 229 days of FCCL operations at 100 percent and 229 days of operations from the Deep Basin Assets. See the Oil Sands and Deep Basin sections of this MD&A for more details. 18 | CENOVUS ENERGY OIL SANDS In 2018, we: 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 the natural gas production is used as fuel at the adjacent Foster Creek operations. • • • • • • Increased total production by 24 percent over 2017 primarily due to the Acquisition; Earned crude oil netbacks of $19.70 per barrel, excluding realized risk management activities, a 20 percent decrease compared with 2017; Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017; Invested $198 million of growth capital to progress Christina Lake phase G, which is expected to be completed ahead of schedule and approximately 25 percent below the anticipated capital required to achieve the planned scope of work; cumulative project allowable costs; and Achieved project payout for royalty purposes at Christina Lake upon cumulative project revenues exceeding Generated Operating Margin net of capital investment of $202 million, an 84 percent decrease compared with 2017 as higher sales volumes were more than offset by increased transportation and blending costs, and realized risk management losses of $1,551 million compared with losses of $307 million in 2017. Oil Sands – Crude Oil Financial Results (1) ($ 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 (1) Excludes results from the Athabasca natural gas property. Operating Margin Variance 2018 10,013 473 9,540 5,879 1,024 1,551 1,086 886 200 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 1,944 1,263 1,244 243 2,231 534 2,175 156 1,086 Year Ended December 31, 2017 Price (1) Volume Condensate Revenue (1) Realized Risk Management Royalties Operating Expenses Year Ended Transportation and Blending (1) December 31, 2018 (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. ) s n o i l l i m $ ( 6,000 5,000 4,000 3,000 2,000 1,000 0 Revenues Price In 2018, our average realized crude oil sales price decreased to $37.51 per barrel (2017 – $41.49 per barrel). Light oil and condensate benchmark prices increased significantly in 2018, while at the same time, light-heavy crude oil price differentials increased, leaving heavy crude oil benchmark prices relatively unchanged year over year. Our realized 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 falling crude oil price environment, we expect to see a negative impact on our bitumen sales price as we are using condensate purchased at a higher price earlier in the year. • • • • In 2018, we: • • 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 the natural gas production is used as fuel at the adjacent Foster Creek operations. Increased total production by 24 percent over 2017 primarily due to the Acquisition; Earned crude oil netbacks of $19.70 per barrel, excluding realized risk management activities, a 20 percent decrease compared with 2017; Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017; Invested $198 million of growth capital to progress Christina Lake phase G, which is expected to be completed ahead of schedule and approximately 25 percent below the anticipated capital required to achieve the planned scope of work; Achieved project payout for royalty purposes at Christina Lake upon cumulative project revenues exceeding cumulative project allowable costs; and Generated Operating Margin net of capital investment of $202 million, an 84 percent decrease compared with 2017 as higher sales volumes were more than offset by increased transportation and blending costs, and realized risk management losses of $1,551 million compared with losses of $307 million in 2017. REPORTABLE SEGMENTS Our reportable segments are as follows: Oil Sands, which includes the development and production of bitumen 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 2.8 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. These 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 include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices. In 2017, Cenovus announced its intention to divest of its Conventional segment that included its heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of operations have been reported as discontinued operations. As at January 5, 2018, all of the Conventional segment assets were sold. Refer to the Discontinued Operations section of this MD&A for more information. Revenues by Reportable Segment ($ millions) Oil Sands (1) Deep Basin (1) Refining and Marketing Corporate and Eliminations 2018 9,553 832 11,183 (724 ) 20,844 2017 7,132 514 9,852 (455 ) 2016 2,920 - 8,439 (353 ) 17,043 11,006 Oil Sands – Crude Oil Financial Results (1) ($ 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 (1) Excludes results from the Athabasca natural gas property. Operating Margin Variance ) s n o i l l i m $ ( 6,000 5,000 4,000 3,000 2,000 1,000 0 2,231 534 1,944 1,263 1,244 243 2018 10,013 473 9,540 5,879 1,024 1,551 1,086 886 200 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 2,175 156 1,086 Year Ended December 31, 2017 Price (1) Volume Condensate Revenue (1) Realized Risk Management Royalties Transportation and Blending (1) Operating Expenses Year Ended December 31, 2018 (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. (1) Our 2017 results include 229 days of FCCL operations at 100 percent and 229 days of operations from the Deep Basin Assets. See the Oil Sands and Deep Basin sections of this MD&A for more details. Revenues Price In 2018, our average realized crude oil sales price decreased to $37.51 per barrel (2017 – $41.49 per barrel). Light oil and condensate benchmark prices increased significantly in 2018, while at the same time, light-heavy crude oil price differentials increased, leaving heavy crude oil benchmark prices relatively unchanged year over year. Our realized 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 falling crude oil price environment, we expect to see a negative impact on our bitumen sales price as we are using condensate purchased at a higher price earlier in the year. 2018 ANNUAL REPORT | 19 With WCS benchmark prices remaining flat in 2018 and the higher cost of condensate used in blending, our realized crude oil sales price was negatively impacted. The decrease in our crude oil price also reflects the wider WCS-Christina Dilbit Blend (“CDB”) differential, which increased to a discount of US$3.17 per barrel (2017 – discount of US$1.67 per barrel). Expenses Transportation and Blending Production Volumes (barrels per day) Foster Creek Christina Lake 2018 161,979 201,017 362,996 Percent Change 30 20 24 2017 124,752 167,727 292,479 Percent Change 78 111 95 2016 70,244 79,449 149,693 Oil Sands production averaged 362,996 barrels per day in 2018, a 24 percent increase primarily due to the Acquisition contributing a full year of volumes in 2018 compared with incremental volumes for 229 days in 2017. In response to limited takeaway capacity and discounted heavy oil pricing, we made the decision to operate our Christina Lake and Foster Creek facilities at reduced production levels in the first quarter of 2018, and again starting in mid-September, leaving crude oil barrels in our reservoir to produce at a later date. Our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory as pipeline capacity improves and crude oil differentials narrow. Stored volumes from the first quarter of 2018 were recovered in the second quarter as we ramped up production rates in response to narrowing crude oil differentials. Voluntary production curtailments from mid-September onward lowered our annualized 2018 production by approximately 13,000 barrels per day. The impact of curtailed production was mostly offset by improved operational performance at both oil sands facilities during the second and third quarters of 2018. 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 a wider WCS-Condensate differential in 2018, the proportion of the cost of condensate recovered decreased. 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. Royalties for 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. Royalties for 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 revenues less diluent costs and transportation costs. Net profits are a function of sales revenues less diluent costs, transportation costs, and allowed operating and capital costs. Foster Creek is a post-payout project. During the third quarter of 2018, our Christina Lake property achieved project payout. Project payout is achieved when the cumulative project revenue exceeds the cumulative project allowable costs. The Christina Lake effective royalty rate increased to an average of 4.8 percent in 2018 from an average of 2.5 percent in 2017. Effective Royalty Rates (percent) Foster Creek Christina Lake 2018 18.0 4.8 2017 11.4 2.5 2016 - 1.6 (1) Netbacks reflect our operating margin on a per-barrel basis of unblended crude oil. Royalties increased $243 million in 2018 compared with 2017. Royalties at both Foster Creek and Christina Lake increased primarily due to a higher average WTI benchmark price (which determines the royalty rate), and higher volumes. In addition, Christina Lake achieving project payout in August 2018 increased royalty expenses during the third quarter, which was partially offset during the fourth quarter as higher crude oil differentials negatively impacted project revenues. Risk management positions in 2018 resulted in realized losses of $1,551 million (2017 – realized losses of $307 million), consistent with average benchmark prices exceeding our contract prices. In 2017 we entered into hedging contracts with the intent to provide downside protection and support financial resilience following the 20 | CENOVUS ENERGY Transportation and blending costs increased $2,175 million compared with 2017 primarily due to the Acquisition. Blending costs increased primarily due to a rise in condensate volumes required for our increased production, as well as higher condensate prices, driven by higher light oil benchmark 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. Per-unit Transportation Expenses At Foster Creek, transportation costs decreased $0.39 per barrel due to a higher proportion of Canadian sales resulting in lower costs associated with pipeline tariffs. Christina Lake transportation costs increased $0.73 per barrel as a result of increased U.S. sales relative to 2017. Primary drivers of our operating expenses in 2018 were workforce costs, fuel, chemical costs, repairs and maintenance and workovers. Total operating expenses increased $156 million primarily due to the Acquisition, increased chemical prices and increased natural gas consumption as a result of higher steam production in 2018, partially offset by a decrease in natural gas prices, lower workforce costs, and fewer workovers. Per-unit Operating Expenses At both Foster Creek and Christina Lake, per-barrel fuel costs decreased in 2018 primarily due to lower natural gas prices. Foster Creek per-barrel non-fuel operating expenses decreased primarily due to higher sales volumes, a reduction in workforce costs, fewer workovers and lower repairs and maintenance costs, partially offset by higher chemical costs. At Christina Lake, per-barrel non-fuel operating expenses decreased due to higher sales volumes and lower workforce costs, partially offset by increased chemical costs. 2018 Percent Change Percent Change 2.13 6.84 8.97 1.87 4.73 6.60 7.65 (13 ) (15 ) (14 ) (9 ) (1 ) (4 ) (9 ) 2017 2.44 8.02 10.46 2.06 4.78 6.84 8.40 2016 2.46 8.09 10.55 2.08 5.40 7.48 8.91 (1 ) (1 ) (1 ) (1 ) (11 ) (9 ) (6 ) Foster Creek Christina Lake 2018 2017 2016 2018 2017 42.63 43.75 30.32 33.42 39.78 6.25 8.34 8.97 4.00 8.73 (0.01 ) 8.84 10.46 10.55 1.37 5.25 6.60 0.87 4.52 6.84 2016 25.30 0.33 4.68 7.48 19.07 (11.49 ) 20.56 (2.95 ) 10.94 20.20 3.51 (11.66 ) 27.55 (2.99 ) 12.81 3.08 7.58 17.61 14.45 8.54 24.56 15.89 Operating ($/bbl) Foster Creek Christina Lake Fuel Non-fuel Total Fuel Non-fuel Total Total 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 Acquisition. With WCS benchmark prices remaining flat in 2018 and the higher cost of condensate used in blending, our realized crude oil sales price was negatively impacted. The decrease in our crude oil price also reflects the wider WCS-Christina Dilbit Blend (“CDB”) differential, which increased to a discount of US$3.17 per barrel (2017 – discount of US$1.67 per Expenses Transportation and Blending Condensate volumes. Royalties project. barrel). Production Volumes (barrels per day) Foster Creek Christina Lake 2018 161,979 201,017 362,996 Percent Change 30 20 24 2017 124,752 167,727 292,479 Percent Change 78 111 95 2016 70,244 79,449 149,693 Oil Sands production averaged 362,996 barrels per day in 2018, a 24 percent increase primarily due to the Acquisition contributing a full year of volumes in 2018 compared with incremental volumes for 229 days in 2017. In response to limited takeaway capacity and discounted heavy oil pricing, we made the decision to operate our Christina Lake and Foster Creek facilities at reduced production levels in the first quarter of 2018, and again starting in mid-September, leaving crude oil barrels in our reservoir to produce at a later date. Our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory as pipeline capacity improves and crude oil differentials narrow. Stored volumes from the first quarter of 2018 were recovered in the second quarter as we ramped up production rates in response to narrowing crude oil differentials. Voluntary production curtailments from mid-September onward lowered our annualized 2018 production by approximately 13,000 barrels per day. The impact of curtailed production was mostly offset by improved operational performance at both oil sands facilities during the second and third quarters of 2018. 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 a wider WCS-Condensate differential in 2018, the proportion of the cost of condensate recovered decreased. The total amount of condensate used increased as a result of higher production 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. Royalties for 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 Royalties for 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 revenues less diluent costs and transportation costs. Net profits are a function of sales revenues less diluent costs, transportation costs, and allowed operating and capital costs. Foster Creek is a post-payout project. During the third quarter of 2018, our Christina Lake property achieved project payout. Project payout is achieved when the cumulative project revenue exceeds the cumulative project allowable costs. The Christina Lake effective royalty rate increased to an average of 4.8 percent in 2018 from an average of 2.5 percent in 2017. Effective Royalty Rates (percent) Foster Creek Christina Lake 2018 18.0 4.8 2017 11.4 2.5 2016 - 1.6 Royalties increased $243 million in 2018 compared with 2017. Royalties at both Foster Creek and Christina Lake increased primarily due to a higher average WTI benchmark price (which determines the royalty rate), and higher volumes. In addition, Christina Lake achieving project payout in August 2018 increased royalty expenses during the third quarter, which was partially offset during the fourth quarter as higher crude oil differentials negatively impacted project revenues. Transportation and blending costs increased $2,175 million compared with 2017 primarily due to the Acquisition. Blending costs increased primarily due to a rise in condensate volumes required for our increased production, as well as higher condensate prices, driven by higher light oil benchmark 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. Per-unit Transportation Expenses At Foster Creek, transportation costs decreased $0.39 per barrel due to a higher proportion of Canadian sales resulting in lower costs associated with pipeline tariffs. Christina Lake transportation costs increased $0.73 per barrel as a result of increased U.S. sales relative to 2017. Operating Primary drivers of our operating expenses in 2018 were workforce costs, fuel, chemical costs, repairs and maintenance and workovers. Total operating expenses increased $156 million primarily due to the Acquisition, increased chemical prices and increased natural gas consumption as a result of higher steam production in 2018, partially offset by a decrease in natural gas prices, lower workforce costs, and fewer workovers. Per-unit Operating Expenses ($/bbl) Foster Creek Fuel Non-fuel Total Christina Lake Fuel Non-fuel Total Total 2018 Percent Change 2.13 6.84 8.97 1.87 4.73 6.60 7.65 (13 ) (15 ) (14 ) (9 ) (1 ) (4 ) (9 ) 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 At both Foster Creek and Christina Lake, per-barrel fuel costs decreased in 2018 primarily due to lower natural gas prices. Foster Creek per-barrel non-fuel operating expenses decreased primarily due to higher sales volumes, a reduction in workforce costs, fewer workovers and lower repairs and maintenance costs, partially offset by higher chemical costs. At Christina Lake, per-barrel non-fuel operating expenses decreased due to higher sales volumes and lower workforce costs, partially offset by increased chemical costs. 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 2018 42.63 6.25 8.34 8.97 2017 43.75 4.00 8.73 10.46 2016 30.32 (0.01 ) 8.84 10.55 2018 33.42 1.37 5.25 6.60 2017 39.78 0.87 4.52 6.84 2016 25.30 0.33 4.68 7.48 19.07 (11.49 ) 20.56 (2.95 ) 10.94 3.51 20.20 (11.66 ) 27.55 (2.99 ) 12.81 3.08 7.58 17.61 14.45 8.54 24.56 15.89 (1) Netbacks reflect our operating margin on a per-barrel basis of unblended crude oil. Risk Management Risk management positions in 2018 resulted in realized losses of $1,551 million (2017 – realized losses of $307 million), consistent with average benchmark prices exceeding our contract prices. In 2017 we entered into hedging contracts with the intent to provide downside protection and support financial resilience following the Acquisition. 2018 ANNUAL REPORT | 21 Oil Sands – Capital Investment Exploration Expense ($ millions) Foster Creek Christina Lake Other (1) Capital Investment (2) 2018 2017 2016 379 445 824 63 887 455 426 881 92 973 263 282 545 59 604 Includes new resource plays, Narrows Lake, Telephone Lake and Athabasca natural gas. Includes expenditures on PP&E and E&E assets. (1) (2) Oil Sands capital investment decreased $86 million in 2018 primarily due to a smaller sustaining well and re-drill program, as well as decreased spending on the Christina Lake phase G expansion compared with 2017. At Foster Creek, capital investment focused on sustaining capital related to existing production and stratigraphic test wells. Christina Lake capital investment focused on sustaining capital related to existing production, stratigraphic test wells and the phase G expansion. Drilling Activity Foster Creek Christina Lake Other Gross Stratigraphic Test Wells 2018 43 63 106 23 129 2017 96 108 204 16 220 Gross Production Wells (1) 2016 95 104 199 6 205 2018 14 38 52 3 55 2017 2016 41 25 66 - 66 18 35 53 1 54 (1) SAGD well pairs are counted as a single producing well. 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 2019 is forecast to be between $250 million and $300 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 2019 is forecast to be between $425 million and $475 million, focused on sustaining capital and completing 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 ahead of schedule and is expected to be completed in the second quarter of 2019. We have flexibility on when we start production from Christina Lake phase G and will take into consideration whether mandated production curtailments have been lifted and there is sustained improvement in market access and heavy oil benchmark prices. In 2019, we plan to spend a minimal amount of capital on Foster Creek phase H, Christina Lake phase H and Narrows Lake to continue to advance each one to sanction-ready status. Our Technology and other capital investment, forecast to be between $55 million and $65 million in 2019, relates to advancing key strategic initiatives that are expected to provide both cost and environmental benefits. This includes ongoing work on solvents, partial upgrading and advancing our new oil sands facility design. DD&A We deplete crude oil and natural gas properties on a unit-of-production basis over total 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 2018, Oil Sands DD&A increased by $209 million compared with 2017 as a result of increased production volumes. The average depletion rate for the year ended December 31, 2018 was approximately $10.60 per barrel (2017 – $11.50 per barrel). Future development costs declined due to an increase in well pair lengths at Christina Lake, resulting in a reduction in the number of pads and well pairs required, as well as cost savings at both Foster Creek and Christina Lake related to a reduction in per well costs. This decline was partially offset by an increase in the future development costs at Foster Creek as a result of a development area expansion. 22 | CENOVUS ENERGY Exploration expense of $6 million was recorded for the year ended December 31, 2018. In 2017, we expensed $888 million primarily related to E&E assets in the Greater Borealis area that were deemed not to be technically feasible or commercially viable. 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 Our Deep Basin Assets include liquids rich natural gas, condensate and other NGLs, as well as light and medium oil 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 provide short-cycle development opportunities with high-return potential that complement our long-term oil sands development. In addition, a portion of the natural gas produced is used as fuel in our oil sands operations and provides an economic hedge for the natural gas required as a fuel source at the Refineries. In 2018, we: Produced a total of 120,258 BOE per day; Invested capital of $211 million, primarily in the first three months of the year, related to drilling 15 net horizontal production wells and completing 21 net wells, as well as capital related to facilities and infrastructure to support Earned a netback of $7.09 per BOE, excluding realized risk management activities; Generated Operating Margin of $312 million; and Closed the divestiture of CPP on September 6, 2018 for cash proceeds of $625 million, before closing going forward. DEEP BASIN • • • • • production; adjustments. Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Revenues Price Light and Medium Oil ($/bbl) NGLs ($/bbl) Natural Gas ($/mcf) Total Oil Equivalent ($/BOE) May 17 - December 31, 2018 904 72 832 90 403 1 26 312 211 101 2017 555 41 514 56 250 1 - 207 225 (18 ) May 17 - December 31, 2018 66.71 38.56 1.72 19.31 2017 60.01 33.05 2.03 19.52 For the year ended December 31, 2018, revenues include $57 million of processing fee revenue related to our interests in natural gas processing facilities (2017 – $31 million). We do not include processing fee revenue in our per-unit pricing metrics or our netbacks. 2018 2017 2016 379 445 824 63 887 455 426 881 92 973 263 282 545 59 604 ($ millions) Foster Creek Christina Lake Other (1) Capital Investment (2) and the phase G expansion. Drilling Activity Foster Creek Christina Lake Other Includes new resource plays, Narrows Lake, Telephone Lake and Athabasca natural gas. (1) (2) Includes expenditures on PP&E and E&E assets. Oil Sands capital investment decreased $86 million in 2018 primarily due to a smaller sustaining well and re-drill program, as well as decreased spending on the Christina Lake phase G expansion compared with 2017. At Foster Creek, capital investment focused on sustaining capital related to existing production and stratigraphic test wells. Christina Lake capital investment focused on sustaining capital related to existing production, stratigraphic test wells Gross Stratigraphic Test Wells Gross Production Wells (1) 2018 2017 2016 2018 2017 2016 43 63 106 23 129 96 108 204 16 220 95 104 199 6 205 14 38 52 3 55 41 25 66 - 66 18 35 53 1 54 (1) SAGD well pairs are counted as a single producing well. 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 2019 is forecast to be between $250 million and $300 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 2019 is forecast to be between $425 million and $475 million, focused on sustaining capital and completing 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 ahead of schedule and is expected to be completed in the second quarter of 2019. We have flexibility on when we start production from Christina Lake phase G and will take into consideration whether mandated production curtailments have been lifted and there is sustained improvement in market access and heavy oil benchmark prices. In 2019, we plan to spend a minimal amount of capital on Foster Creek phase H, Christina Lake phase H and Narrows Lake to continue to advance each one to sanction-ready status. Our Technology and other capital investment, forecast to be between $55 million and $65 million in 2019, relates to advancing key strategic initiatives that are expected to provide both cost and environmental benefits. This includes ongoing work on solvents, partial upgrading and advancing our new oil sands facility design. DD&A We deplete crude oil and natural gas properties on a unit-of-production basis over total 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 2018, Oil Sands DD&A increased by $209 million compared with 2017 as a result of increased production volumes. The average depletion rate for the year ended December 31, 2018 was approximately $10.60 per barrel (2017 – $11.50 per barrel). Future development costs declined due to an increase in well pair lengths at Christina Lake, resulting in a reduction in the number of pads and well pairs required, as well as cost savings at both Foster Creek and Christina Lake related to a reduction in per well costs. This decline was partially offset by an increase in the future development costs at Foster Creek as a result of a development area expansion. Oil Sands – Capital Investment Exploration Expense Exploration expense of $6 million was recorded for the year ended December 31, 2018. In 2017, we expensed $888 million primarily related to E&E assets in the Greater Borealis area that were deemed not to be technically feasible or commercially viable. 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. DEEP BASIN Our Deep Basin Assets include liquids rich natural gas, condensate and other NGLs, as well as light and medium oil 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 provide short-cycle development opportunities with high-return potential that complement our long-term oil sands development. In addition, a portion of the natural gas produced is used as fuel in our oil sands operations and provides an economic hedge for the natural gas required as a fuel source at the Refineries. In 2018, we: • • Produced a total of 120,258 BOE per day; Invested capital of $211 million, primarily in the first three months of the year, related to drilling 15 net horizontal production wells and completing 21 net wells, as well as capital related to facilities and infrastructure to support production; Earned a netback of $7.09 per BOE, excluding realized risk management activities; Generated Operating Margin of $312 million; and Closed the divestiture of CPP on September 6, 2018 for cash proceeds of $625 million, before closing adjustments. • • • Financial Results ($ millions) Gross Sales Less: Royalties Revenues Expenses Transportation and Blending Operating Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Capital Investment Operating Margin Net of Related Capital Investment Revenues Price Light and Medium Oil ($/bbl) NGLs ($/bbl) Natural Gas ($/mcf) Total Oil Equivalent ($/BOE) May 17 - December 31, 2017 555 41 514 2018 904 72 832 90 403 1 26 312 211 101 56 250 1 - 207 225 (18 ) May 17 - December 31, 2017 60.01 33.05 2.03 19.52 2018 66.71 38.56 1.72 19.31 For the year ended December 31, 2018, revenues include $57 million of processing fee revenue related to our interests in natural gas processing facilities (2017 – $31 million). We do not include processing fee revenue in our per-unit pricing metrics or our netbacks. 2018 ANNUAL REPORT | 23 Production Volumes Liquids Crude Oil (barrels per day) NGLs (barrels per day) Natural Gas (MMcf per day) Total Production (BOE/d) Natural Gas Production (percentage of total) Liquids Production (percentage of total) 2018 2017 Risk management activities in 2018 resulted in realized losses of $26 million (2017 – $nil). 5,916 26,538 32,454 527 120,258 73 27 3,922 16,928 20,850 316 73,492 72 28 In 2018, production from the Deep Basin Assets was 120,258 BOE per day, a three percent increase in production from the closing of the Acquisition on May 17, 2017 to December 31, 2017, which averaged 117,138 BOE per day. The increase in production was primarily due to strong performance from the drilling program, partially offset by the divestiture of CPP on September 6, 2018. Production from CPP was approximately 8,800 BOE per day prior to the divestiture. Royalties 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 Government of Alberta released a new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”), which applies to all producing wells drilled 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 2018, our effective royalty rate was 12.8 percent for liquids and 3.6 percent for natural gas (2017 – 12.1 percent for liquids and 4.4 percent for natural gas). Expenses Transportation Transportation costs averaged $1.97 per BOE in 2018 compared with $2.08 per BOE in 2017. Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. The majority of Deep Basin production is sold into the Alberta market. Operating Primary drivers of our operating expenses were related to workforce, repairs and maintenance, third-party processing fee expenses, and property tax and lease costs. Total operating expenses increased $153 million, reflecting a full year of operations in 2018 compared with 229 days in 2017, increased processing fees and higher electricity rates, partially offset by a reduction in repairs and maintenance activities, and lower workforce costs. Risk Management Deep Basin – Capital Investment In 2018, capital investment was focused primarily on drilling high liquids yielding wells and de-risking resource potential. We completed the majority of our 2018 drilling program in the first three months of the year, with development focusing on all three operating areas including the drilling of 15 net horizontal wells, completing 21 net wells and bringing 25 net wells on production. Additional capital expenditures were allocated to facilities and infrastructure to support production in our core development areas. ($ millions) Drilling and Completions Facilities Other Capital Investment (1) Drilling Activity (1) Includes expenditures on PP&E, E&E assets and assets held for sale. The following table summarizes Cenovus’s net well activity: May 17 - December 31, 2018 111 56 44 211 2017 152 32 41 225 2018 May 17 - December 31, 2017 Drilled (1) Completed Tied-in Drilled Completed Tied-in 4 8 3 15 6 11 4 21 9 9 7 25 9 7 12 28 5 5 10 20 - 6 8 14 (1) Includes 13 operated net horizontal wells and two non-operated net horizontal wells for the year ended December 31, 2018. Future Capital Investment In the fourth quarter of 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. As a result, we have reduced capital investment and drilling plans in 2019 compared with 2018, with total Deep Basin capital investment forecast to be between $50 million and Elmworth-Wapiti Kaybob-Edson Clearwater Total $75 million. 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. The average depletion rate was approximately $10.55 per BOE for the year ended December 31, 2018 (2017 – $10.25 per BOE). Deep Basin DD&A was $412 million in 2018 (2017 – $331 million). Earlier in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline in forward prices and a slowing of the development plan. The impairment was recorded as additional DD&A. In the fourth quarter of 2018, we reversed $132 million of the impairment losses, net of DD&A that would have been recorded had no impairment been recorded. The reversal was due to an increase of the cash-generating unit’s (“CGUs”) recoverable amount due to improved recovery, extensions and well performance and changes to the development plan. Exploration Expense In the fourth quarter of 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. Based on the revised development plan, it was determined that the carrying value of certain Deep Basin E&E assets were not fully recoverable resulting in previously capitalized E&E costs of $2.1 billion being written off as exploration expense within the Deep Basin segment. Management is committed to developing this significant resource; however, at a much slower pace of development. In 2017, exploration expense was $nil. May 17 - December 31, 2017 2018 19.31 1.64 1.97 8.58 0.03 7.09 (0.59 ) 6.50 19.52 1.54 2.08 8.56 0.02 7.32 - 7.32 Netbacks ($/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 24 | CENOVUS ENERGY 5,916 26,538 32,454 527 120,258 73 27 3,922 16,928 20,850 316 73,492 72 28 Production Volumes Liquids Crude Oil (barrels per day) NGLs (barrels per day) Natural Gas (MMcf per day) Total Production (BOE/d) Natural Gas Production (percentage of total) Liquids Production (percentage of total) divestiture. Royalties In 2018, production from the Deep Basin Assets was 120,258 BOE per day, a three percent increase in production from the closing of the Acquisition on May 17, 2017 to December 31, 2017, which averaged 117,138 BOE per day. The increase in production was primarily due to strong performance from the drilling program, partially offset by the divestiture of CPP on September 6, 2018. Production from CPP was approximately 8,800 BOE per day prior to the 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 Government of Alberta released a new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”), which applies to all producing wells drilled 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 2018, our effective royalty rate was 12.8 percent for liquids and 3.6 percent for natural gas (2017 – 12.1 percent for liquids and 4.4 percent for natural gas). Transportation costs averaged $1.97 per BOE in 2018 compared with $2.08 per BOE in 2017. Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. The majority of Deep Basin production is sold into the Alberta market. Primary drivers of our operating expenses were related to workforce, repairs and maintenance, third-party processing fee expenses, and property tax and lease costs. Total operating expenses increased $153 million, reflecting a full year of operations in 2018 compared with 229 days in 2017, increased processing fees and higher electricity rates, partially offset by a reduction in repairs and maintenance activities, and lower workforce costs. Expenses Transportation Operating Netbacks ($/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 May 17 - December 31, 2018 19.31 1.64 1.97 8.58 0.03 7.09 (0.59 ) 6.50 2017 19.52 1.54 2.08 8.56 0.02 7.32 - 7.32 2018 2017 Risk management activities in 2018 resulted in realized losses of $26 million (2017 – $nil). Risk Management Deep Basin – Capital Investment In 2018, capital investment was focused primarily on drilling high liquids yielding wells and de-risking resource potential. We completed the majority of our 2018 drilling program in the first three months of the year, with development focusing on all three operating areas including the drilling of 15 net horizontal wells, completing 21 net wells and bringing 25 net wells on production. Additional capital expenditures were allocated to facilities and infrastructure to support production in our core development areas. ($ 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 The following table summarizes Cenovus’s net well activity: Elmworth-Wapiti Kaybob-Edson Clearwater Total 2018 Drilled (1) Completed 4 8 3 15 6 11 4 21 Tied-in 9 9 7 25 May 17 - December 31, 2017 2018 111 56 44 211 152 32 41 225 May 17 - December 31, 2017 Drilled Completed 5 9 Tied-in 7 12 28 5 10 20 - 6 8 14 (1) Includes 13 operated net horizontal wells and two non-operated net horizontal wells for the year ended December 31, 2018. Future Capital Investment In the fourth quarter of 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. As a result, we have reduced capital investment and drilling plans in 2019 compared with 2018, with total Deep Basin capital investment forecast to be between $50 million and $75 million. 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. The average depletion rate was approximately $10.55 per BOE for the year ended December 31, 2018 (2017 – $10.25 per BOE). Deep Basin DD&A was $412 million in 2018 (2017 – $331 million). Earlier in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline in forward prices and a slowing of the development plan. The impairment was recorded as additional DD&A. In the fourth quarter of 2018, we reversed $132 million of the impairment losses, net of DD&A that would have been recorded had no impairment been recorded. The reversal was due to an increase of the cash-generating unit’s (“CGUs”) recoverable amount due to improved recovery, extensions and well performance and changes to the development plan. Exploration Expense In the fourth quarter of 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. Based on the revised development plan, it was determined that the carrying value of certain Deep Basin E&E assets were not fully recoverable resulting in previously capitalized E&E costs of $2.1 billion being written off as exploration expense within the Deep Basin segment. Management is committed to developing this significant resource; however, at a much slower pace of development. In 2017, exploration expense was $nil. 2018 ANNUAL REPORT | 25 Assets and Liabilities Held for Sale In the fourth quarter of 2017, we announced our 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. As a result, these assets were classified as assets held for sale and were recorded at the lesser of their carrying amount and fair value less costs to sell. In December 2018, Management decided to discontinue this sales process until market conditions improve. As a result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion, calculated on a per-unit of production basis, was recorded in the fourth quarter. 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 2018, we: • • Completed major planned turnarounds at both Wood River and Borger refineries in the first quarter; Demonstrated new crude processing rates that will increase the nameplate capacities to a combined 482,000 gross barrels per day, effective January 1, 2019; Benefited from higher realized crack spreads due to improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials compared with 2017, which created a feedstock cost advantage at both Refineries; Increased rail volumes loaded at the Bruderheim Energy Terminal, averaging 73,719 barrels per day in December, compared with an average of 18,997 barrels per day loaded in the first half of 2018; Executed rail agreements for capacity to move additional heavy crude oil from northern Alberta; and Generated Operating Margin of $996 million compared with $598 million in 2017. • • • • Refinery Operations (1) Crude Oil Capacity (Mbbls/d) (2) Crude Oil Runs (Mbbls/d) Heavy Crude Oil Light/Medium Refined Products (Mbbls/d) Gasoline Distillate Other Crude Utilization (percent) 2018 2017 2016 460 446 191 255 470 233 156 81 97 460 442 202 240 470 238 149 83 96 460 444 233 211 471 236 146 89 97 (1) (2) Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent. Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day. On a 100 percent basis, the Refineries had total processing capacity in 2018 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. As a result of consistently strong operating performance, higher utilization rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing capacity, effective January 1, 2019. Total processing capacity as at January 1, 2019 is approximately 482,000 gross barrels per day of crude oil. 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, and the discount of WTS 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. Total crude oil runs increased slightly, while refined product output was unchanged compared with 2017 as strong operational performance was partially offset by major planned turnarounds and maintenance at both Refineries in the first quarter of 2018. In 2018, lower heavy crude oil volumes were processed due to the optimization of the total crude input slate, which resulted in increased volumes of WTS being processed at the Borger refinery, in order to take advantage of the wider WTI-WTS crude oil differential. 26 | CENOVUS ENERGY 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 2018 11,183 9,261 1,922 927 (1 ) 996 208 788 2017 9,852 8,476 1,376 772 6 598 180 418 2016 8,439 7,325 1,114 742 26 346 220 126 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 2018, Refining and Marketing gross margin increased primarily due to higher realized crack spreads from improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which created a feedstock cost advantage. As at December 31, 2018, we recorded a $47 million write-down of our refined product inventory due to a decline in prices. The Canadian dollar strengthened relative to the U.S. dollar compared with 2017, which had a negative impact on our gross margin of approximately $10 million. For the year ended December 31, 2018, the cost of RINs was $131 million compared with $296 million in 2017. The cost of RINs declined due primarily to the decrease in RINs benchmark prices as a result of small refiners being granted exemptions from volume obligations. Operating Expense Primary drivers of operating expenses in 2018 were maintenance, labour, and utilities. Operating expenses increased primarily due to higher planned maintenance and turnaround costs compared with 2017. Refining and Marketing – Capital Investment 2018 2017 119 85 4 208 114 54 12 180 2016 147 66 7 220 ($ millions) Wood River Refinery Borger Refinery Marketing improvement projects. DD&A Capital expenditures in 2018 focused primarily on capital maintenance and reliability work, as well as yield In 2019, we expect to invest between $240 million and $275 million and will continue to focus on capital maintenance, reliability work, and yield improvement projects. 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 60 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A was $222 million in 2018 compared with $215 million in 2017. 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, adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by Cenovus’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, 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 and losses, if any, on interest rate swaps and foreign exchange contracts. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, onerous contract provisions, 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. Assets and Liabilities Held for Sale In the fourth quarter of 2017, we announced our 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. As a result, these assets were classified as assets held for sale and were recorded at the lesser of their carrying amount and fair value less costs to sell. In December 2018, Management decided to discontinue this sales process until market conditions improve. As a result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion, calculated on a per-unit of production basis, was recorded in the fourth quarter. 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 2018, we: • • • • • • Completed major planned turnarounds at both Wood River and Borger refineries in the first quarter; Demonstrated new crude processing rates that will increase the nameplate capacities to a combined 482,000 gross barrels per day, effective January 1, 2019; Benefited from higher realized crack spreads due to improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials compared with 2017, which created a feedstock cost advantage at both Refineries; Increased rail volumes loaded at the Bruderheim Energy Terminal, averaging 73,719 barrels per day in December, compared with an average of 18,997 barrels per day loaded in the first half of 2018; Executed rail agreements for capacity to move additional heavy crude oil from northern Alberta; and Generated Operating Margin of $996 million compared with $598 million in 2017. Refinery Operations (1) Crude Oil Capacity (Mbbls/d) (2) Crude Oil Runs (Mbbls/d) Heavy Crude Oil Light/Medium Refined Products (Mbbls/d) Gasoline Distillate Other Crude Utilization (percent) 460 446 191 255 470 233 156 81 97 460 442 202 240 470 238 149 83 96 460 444 233 211 471 236 146 89 97 (1) (2) Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent. Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day. On a 100 percent basis, the Refineries had total processing capacity in 2018 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. As a result of consistently strong operating performance, higher utilization rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing capacity, effective January 1, 2019. Total processing capacity as at January 1, 2019 is approximately 482,000 gross barrels per day of crude oil. 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, and the discount of WTS 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. Total crude oil runs increased slightly, while refined product output was unchanged compared with 2017 as strong operational performance was partially offset by major planned turnarounds and maintenance at both Refineries in the first quarter of 2018. In 2018, lower heavy crude oil volumes were processed due to the optimization of the total crude input slate, which resulted in increased volumes of WTS being processed at the Borger refinery, in order to take advantage of the wider WTI-WTS crude oil differential. 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 2018 11,183 9,261 1,922 927 (1 ) 996 208 788 2017 9,852 8,476 1,376 772 6 598 180 418 2016 8,439 7,325 1,114 742 26 346 220 126 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 2018, Refining and Marketing gross margin increased primarily due to higher realized crack spreads from improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which created a feedstock cost advantage. As at December 31, 2018, we recorded a $47 million write-down of our refined product inventory due to a decline in prices. The Canadian dollar strengthened relative to the U.S. dollar compared with 2017, which had a negative impact on our gross margin of approximately $10 million. For the year ended December 31, 2018, the cost of RINs was $131 million compared with $296 million in 2017. The cost of RINs declined due primarily to the decrease in RINs benchmark prices as a result of small refiners being granted exemptions from volume obligations. Operating Expense Primary drivers of operating expenses in 2018 were maintenance, labour, and utilities. Operating expenses increased primarily due to higher planned maintenance and turnaround costs compared with 2017. 2018 2017 2016 Refining and Marketing – Capital Investment ($ millions) Wood River Refinery Borger Refinery Marketing 2018 2017 119 85 4 208 114 54 12 180 2016 147 66 7 220 Capital expenditures in 2018 focused primarily on capital maintenance and reliability work, as well as yield improvement projects. In 2019, we expect to invest between $240 million and $275 million and will continue to focus on capital maintenance, reliability work, and yield improvement projects. 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 60 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A was $222 million in 2018 compared with $215 million in 2017. 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, adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by Cenovus’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, 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 and losses, if any, on interest rate swaps and foreign exchange contracts. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, onerous contract provisions, 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. 2018 ANNUAL REPORT | 27 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” 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” and accordingly, FCCL has been consolidated. As required by IFRS 3, “Business Combinations” 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 our 2017 net earnings. 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 $132 million as at December 31, 2018 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. For the year ended December 31, 2018, a non-cash re-measurement loss of $50 million was recorded. As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is C$38.87 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately C$35.60 per barrel and C$41.60 per barrel. For the year ended December 31, 2018, $124 million was payable under the contingent payment agreement (2017 – $17 million). 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 2018 was $58 million (2017 – $62 million). Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Total Tax Expense (Recovery) From Continuing Operations 2018 2017 2016 (128 ) 2 (126 ) (884 ) (1,010 ) (217 ) (38 ) (255 ) 203 (52 ) (260 ) 1 (259 ) (84 ) (343 ) DD&A Income Tax ($ millions) Current Tax Canada United States In 2018, our risk management activities resulted in: • • • Unrealized risk management gains of $1,249 million (2017 – losses of $729 million); Realized risk management gains of $23 million on interest rate swaps (2017 – $nil); and Realized risk management losses of $1 million on foreign exchange contracts (2017 – gains of $146 million). ($ millions) General and Administrative Onerous Contract Provisions 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 Expenses General and Administrative 2018 391 629 627 (19 ) 854 - - 50 25 795 (12 ) 3,340 2017 300 8 645 (62 ) (812 ) (2,555 ) 56 (138 ) 36 1 (5 ) (2,526 ) 2016 318 8 390 (52 ) (198 ) - - - 36 6 34 542 Primary drivers of our general and administrative expenses were workforce costs and office rent. In 2018, general and administrative costs increased by $91 million, primarily driven by severance costs of $60 million related to workforce reductions, higher rent costs, and an increase in long-term employee incentive costs related to a smaller decrease in our share price as compared with the decrease in 2017, partially offset by $40 million of transition costs related to the Acquisition that were recorded in 2017. Onerous Contract Provisions The provision for onerous contracts relates to onerous operating leases and operating costs for office space in Calgary, Alberta. The provision represents the present value of the difference between the future lease payments that we are obligated to make under the non-cancellable lease contracts and the estimated sublease recoveries, discounted at our credit-adjusted risk-free rate. For the year ended December 31, 2018, we recorded a non-cash provision for onerous contracts of $629 million (net of $57 million due to the change in the credit-adjusted risk-free discount rate) compared with $8 million in 2017. We are actively managing our real estate portfolio, and in the third quarter of 2018, we reached an agreement to sublease a portion of our Calgary office space that was in excess of our current and near-term requirements. Finance Costs Finance costs include interest expense on our short-term borrowings and long-term debt as well as the unwinding of the discount on decommissioning liabilities. On October 29, 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due October 15, 2019, resulting in a redemption premium of US$20 million and associated unamortized discount and debt issue costs of $1 million that were recognized as finance costs. In December 2018, we paid US$69 million to repurchase unsecured notes with a principal amount of US$76 million. A gain of $9 million on the repurchase was recorded in finance costs. Subsequent to December 31, 2018, we repurchased a further US$324 million of unsecured notes for cash of US$300 million. Finance costs decreased by $18 million in 2018 compared with 2017 due a reduction in total debt, resulting in lower interest expense, partially offset by the premium on redemption of long-term debt. In 2017, finance costs were higher primarily due to costs associated with additional debt incurred to finance the Acquisition, including $3.6 billion borrowed under a committed Bridge Facility that was fully repaid and retired in December 2017. The weighted average interest rate on outstanding debt for 2018 was 5.1 percent (2017 – 4.9 percent). Foreign Exchange ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2018 649 205 854 2017 (857 ) 45 (812 ) 2016 (189 ) (9 ) (198 ) In 2018, unrealized foreign exchange losses were recorded primarily as a result of the translation of our U.S. dollar denominated debt. At December 31, 2018, the Canadian dollar relative to the U.S. dollar was eight percent weaker compared with December 31, 2017, creating unrealized losses in 2018. 28 | CENOVUS ENERGY In 2018, our risk management activities resulted in: • • • Unrealized risk management gains of $1,249 million (2017 – losses of $729 million); Realized risk management gains of $23 million on interest rate swaps (2017 – $nil); and Realized risk management losses of $1 million on foreign exchange contracts (2017 – gains of $146 million). ($ millions) General and Administrative Onerous Contract Provisions 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 Expenses General and Administrative 2018 391 629 627 (19 ) 854 - - 50 25 795 (12 ) 2017 300 8 645 (62 ) (812 ) (2,555 ) 56 (138 ) 36 1 (5 ) 3,340 (2,526 ) 2016 318 8 390 (52 ) (198 ) - - - 36 6 34 542 Primary drivers of our general and administrative expenses were workforce costs and office rent. In 2018, general and administrative costs increased by $91 million, primarily driven by severance costs of $60 million related to workforce reductions, higher rent costs, and an increase in long-term employee incentive costs related to a smaller decrease in our share price as compared with the decrease in 2017, partially offset by $40 million of transition costs related to the Acquisition that were recorded in 2017. Onerous Contract Provisions The provision for onerous contracts relates to onerous operating leases and operating costs for office space in Calgary, Alberta. The provision represents the present value of the difference between the future lease payments that we are obligated to make under the non-cancellable lease contracts and the estimated sublease recoveries, discounted at our credit-adjusted risk-free rate. For the year ended December 31, 2018, we recorded a non-cash provision for onerous contracts of $629 million (net of $57 million due to the change in the credit-adjusted risk-free discount rate) compared with $8 million in 2017. We are actively managing our real estate portfolio, and in the third quarter of 2018, we reached an agreement to sublease a portion of our Calgary office space that was in excess of our current and near-term requirements. Finance Costs Finance costs include interest expense on our short-term borrowings and long-term debt as well as the unwinding of the discount on decommissioning liabilities. On October 29, 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due October 15, 2019, resulting in a redemption premium of US$20 million and associated unamortized discount and debt issue costs of $1 million that were recognized as finance costs. In December 2018, we paid US$69 million to repurchase unsecured notes with a principal amount of US$76 million. A gain of $9 million on the repurchase was recorded in finance costs. Subsequent to December 31, 2018, we repurchased a further US$324 million of unsecured notes for cash of US$300 million. Finance costs decreased by $18 million in 2018 compared with 2017 due a reduction in total debt, resulting in lower interest expense, partially offset by the premium on redemption of long-term debt. In 2017, finance costs were higher primarily due to costs associated with additional debt incurred to finance the Acquisition, including $3.6 billion borrowed under a committed Bridge Facility that was fully repaid and retired in December 2017. The weighted average interest rate on outstanding debt for 2018 was 5.1 percent (2017 – 4.9 percent). Foreign Exchange ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2018 649 205 854 2017 (857 ) 45 (812 ) 2016 (189 ) (9 ) (198 ) In 2018, unrealized foreign exchange losses were recorded primarily as a result of the translation of our U.S. dollar denominated debt. At December 31, 2018, the Canadian dollar relative to the U.S. dollar was eight percent weaker compared with December 31, 2017, creating unrealized losses in 2018. 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” 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” and accordingly, FCCL has been consolidated. As required by IFRS 3, “Business Combinations” 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 our 2017 net earnings. 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 $132 million as at December 31, 2018 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. For the year ended December 31, 2018, a non-cash re-measurement loss of $50 million was recorded. As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is C$38.87 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately C$35.60 per barrel and C$41.60 per barrel. For the year ended December 31, 2018, $124 million was payable under the contingent payment agreement (2017 – $17 million). 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 2018 was $58 million (2017 – $62 million). Income Tax ($ millions) Current Tax Canada United States Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Total Tax Expense (Recovery) From Continuing Operations 2018 2017 2016 (128 ) 2 (126 ) (884 ) (1,010 ) (217 ) (38 ) (255 ) 203 (52 ) (260 ) 1 (259 ) (84 ) (343 ) 2018 ANNUAL REPORT | 29 The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: DISCONTINUED OPERATIONS ($ millions) Earnings (Loss) From Continuing Operations Before Income Tax Canadian Statutory Rate (percent) 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 U.S. Statutory Rate Non-Deductible Expenses Other Total Tax Expense (Recovery) From Continuing Operations Effective Tax Rate (percent) 2018 (3,926 ) 27.0 (1,060 ) (57 ) 82 99 3 - (78 ) - 2 (1 ) (1,010 ) 25.7 2017 2,216 27.0 598 (17 ) (129 ) (99 ) (41 ) (68 ) - (275 ) (5 ) (16 ) (52 ) (2.3 ) 2016 (802 ) 27.0 (217 ) (46 ) (26 ) (26 ) (46 ) - - - 5 13 (343 ) 42.8 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 and 2018, cash tax recoveries were recorded associated with prior year taxes paid. The maximum recovery was reached in 2018 and we expect cash tax expense in 2019. In 2018, we recorded a deferred tax recovery related to current period losses, including the write down of the Deep Basin E&E assets, and a $78 million recovery arising from an adjustment to the tax basis of our refining assets. The increase in tax basis was a result of our partner recognizing a taxable gain on their interest in WRB Refining LP (“WRB”) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. A deferred tax expense on continuing operations was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, net of a tax benefit related to the reduction of the US federal corporate tax rate from 35 percent to 21 percent. 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-recognition of capital losses. In 2017, Cenovus divested the majority of its Conventional segment which included its heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were reclassified as held for sale and the results of operations reported as a discontinued operation. On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of $343 million The divestitures completed in 2017 generated total gross cash proceeds of $3.2 billion before closing adjustments was recorded on the sale. and a before-tax gain of $1.3 billion. Financial Results ($ 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 2018 14 3 11 1 (28 ) 1 - 37 - - 1 36 - 9 27 220 247 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 ) 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 $81 million deferred tax expense in the year ended December 31, 2018 (2017 – $347 million deferred tax expense). QUARTERLY RESULTS Our results over the last eight quarters were impacted primarily by volatility in commodity prices, as well as the increase to production volumes due to the Acquisition. Light oil benchmark prices improved through the majority of 2018; however, market conditions resulted in a substantial fall in the price of WTI in the fourth quarter of 2018, ending the year more than 20 percent below where it started in January 2018. At the same time, light-heavy crude oil differentials increased significantly, most prominently in the fourth quarter of 2018 when the differential between WTI and WCS benchmark prices hit a record of US$52.00 per barrel. As a result, our companywide Netback from continuing operations averaged negative $1.13 per BOE in the fourth quarter of 2018, before realized risk management activities, a substantial decrease from $22.38 per BOE in the fourth quarter of 2017. Historical Crude Oil Benchmark Prices 75 65 55 45 35 25 15 ) l b b / $ S U e g a r e v a ( Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2018 2017 WTI WCS 30 | CENOVUS ENERGY The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: DISCONTINUED OPERATIONS ($ millions) Earnings (Loss) From Continuing Operations Before Income Tax Canadian Statutory Rate (percent) 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 U.S. Statutory Rate Non-Deductible Expenses Other Total Tax Expense (Recovery) From Continuing Operations Effective Tax Rate (percent) 2018 (3,926 ) 27.0 (1,060 ) (57 ) 82 99 3 - (78 ) - 2 (1 ) (1,010 ) 25.7 2017 2,216 27.0 598 (17 ) (129 ) (99 ) (41 ) (68 ) - (275 ) (5 ) (16 ) (52 ) (2.3 ) 2016 (802 ) 27.0 (217 ) (46 ) (26 ) (26 ) (46 ) - - - 5 13 (343 ) 42.8 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 and 2018, cash tax recoveries were recorded associated with prior year taxes paid. The maximum recovery was reached in 2018 and we expect cash tax expense in 2019. In 2018, we recorded a deferred tax recovery related to current period losses, including the write down of the Deep Basin E&E assets, and a $78 million recovery arising from an adjustment to the tax basis of our refining assets. The increase in tax basis was a result of our partner recognizing a taxable gain on their interest in WRB Refining LP (“WRB”) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. A deferred tax expense on continuing operations was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, net of a tax benefit related to the reduction of the US federal corporate tax rate from 35 percent to 21 percent. 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-recognition of capital losses. In 2017, Cenovus divested the majority of its Conventional segment which included its heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were reclassified as held for sale and the results of operations reported as a discontinued operation. On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of $343 million was recorded on the sale. The divestitures completed in 2017 generated total gross cash proceeds of $3.2 billion before closing adjustments and a before-tax gain of $1.3 billion. Financial Results ($ 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 (Loss) on Discontinuance (1) Net Earnings (Loss) From Discontinued Operations 2018 14 3 11 1 (28 ) 1 - 37 - - 1 36 - 9 27 220 247 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 ) (1) Net of $81 million deferred tax expense in the year ended December 31, 2018 (2017 – $347 million deferred tax expense). QUARTERLY RESULTS Our results over the last eight quarters were impacted primarily by volatility in commodity prices, as well as the increase to production volumes due to the Acquisition. Light oil benchmark prices improved through the majority of 2018; however, market conditions resulted in a substantial fall in the price of WTI in the fourth quarter of 2018, ending the year more than 20 percent below where it started in January 2018. At the same time, light-heavy crude oil differentials increased significantly, most prominently in the fourth quarter of 2018 when the differential between WTI and WCS benchmark prices hit a record of US$52.00 per barrel. As a result, our companywide Netback from continuing operations averaged negative $1.13 per BOE in the fourth quarter of 2018, before realized risk management activities, a substantial decrease from $22.38 per BOE in the fourth quarter of 2017. Historical Crude Oil Benchmark Prices 75 65 55 45 35 25 15 ) l b b / $ S U e g a r e v a ( Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 WTI WCS 2018 2018 ANNUAL REPORT | 31 Selected Operating and Consolidated Financial Results Revenues ($ millions, except per share amounts or where otherwise indicated) Q4 2018 Q3 Q2 Q1 Q4 2017 Q3 Q2 Q1 Revenues decreased $534 million in 2018 primarily due to: • Wider light-heavy crude oil differentials resulting in a 71 percent decrease in our liquids sales prices from Production Volumes Liquids (barrels per day) Natural Gas (MMcf per day) Total Production (BOE per day) Total Production From Continuing Operations (BOE per day) Refinery Operations Crude Oil Runs (Mbbls/d) Refined Products (Mbbls/d) Revenues Operating Margin (1) 354,592 408,950 423,340 395,474 422,157 449,055 333,664 234,914 363 432,714 495,608 518,609 488,561 554,606 590,851 436,929 295,414 469 558 572 795 851 520 620 432,713 495,592 518,530 487,464 480,497 478,817 322,792 184,001 477 502 492 518 464 490 349 369 450 480 462 490 449 476 406 433 4,545 5,857 5,832 4,610 5,079 4,386 4,037 3,541 From Continuing Operations 135 1,191 911 157 1,018 1,097 572 Total Operating Margin 132 1,192 938 169 1,088 1,214 731 Cash From Operating Activities From Continuing Operations 488 1,258 506 (134 ) 833 481 1,102 Total Cash From Operating Activities 485 1,259 533 (123 ) 900 592 1,239 Adjusted Funds Flow (2) From Continuing Operations (33 ) 976 747 (53 ) 796 865 603 Total Adjusted Funds Flow (36 ) 977 774 (41 ) 866 980 745 305 450 195 328 183 323 Operating Earnings (Loss) (2) From Continuing Operations Per Share ($) (3) (1,670 ) (1.36 ) (41 ) (0.03 ) (292 ) (0.24 ) (752 ) (0.61 ) (533 ) (0.43 ) Total Operating Earnings (Loss) Per Share ($) (3) (1,672 ) (1.36 ) (42 ) (0.03 ) (272 ) (0.22 ) (743 ) (0.60 ) (514 ) (0.42 ) 240 0.20 327 0.27 298 0.27 352 0.32 (39 ) (0.05 ) (39 ) (0.05 ) Net Earnings (Loss) From Continuing Operations Per Share ($) (3) Total Net Earnings (Loss) Per Share ($) (3) Capital Investment (4) From Continuing Operations (1,350 ) (1.10 ) (242 ) (0.20 ) (410 ) (0.33 ) (914 ) (0.74 ) (776 ) (0.63 ) 275 2,558 2.30 0.22 (1,356 ) (1.10 ) (241 ) (0.20 ) (418 ) (0.34 ) (654 ) (0.53 ) 620 0.50 (82 ) 2,617 2.35 (0.07 ) 276 271 294 522 557 396 277 Total Capital Investment 276 271 292 524 583 438 327 Dividends 211 0.25 211 0.25 225 313 Cash Dividends Per Share ($) 41 0.05 Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements, in Notes 1 and 9 of the Interim Consolidated Financial Statements and defined in this MD&A. Non-GAAP measure defined in this MD&A. Represented on a basic and diluted per share basis. Includes expenditures on PP&E, E&E assets, and assets held for sale. 62 0.05 60 0.05 62 0.05 61 0.05 62 0.05 61 0.05 61 0.05 (1) (2) (3) (4) Fourth Quarter 2018 Results Compared With the Fourth Quarter 2017 Continuing Operations Production Volumes Total production from continuing operations decreased 10 percent in the fourth quarter of 2018 compared with 2017. The decrease in production was primarily due to our decision to manage oil sands production rates in response to takeaway capacity constraints and wider heavy oil differentials. Restricting production well rates reduced oil sands production by approximately 51,000 barrels per day in the fourth quarter of 2018 compared with 2017. Refinery Operations Crude oil runs and refined product output increased compared with 2017, with both Refineries operating above nameplate capacity. 32 | CENOVUS ENERGY • • • • • ) s n o i l l i m $ ( 1,200 1,000 800 600 400 200 0 -200 -400 continuing operations to $13.26 per barrel; and • Decreased sales volumes due to lower production. The decreases above were partially offset by increased refining revenues due to higher realized crack spreads and increased crude utilization rates, higher revenues from third-party crude oil and natural gas sales undertaken by the marketing group, as well as lower crude oil royalties. Operating Margin Operating Margin from continuing operations decreased 87 percent in the fourth quarter of 2018 compared with 2017. Upstream Operating Margin decreased by $820 million due to: A decrease in our average liquids sales prices due to wider light-heavy crude oil differentials and higher condensate costs; Increased transportation and blending expenses related to an increase in the price of condensate; and Decreased sales volumes due to lower production. These decreases were partially offset by: Lower royalties primarily due to a lower realized liquids sales price; and Realized risk management losses of $86 million compared with losses of $235 million in 2017. Refining and Marketing Operating Margin decreased by $63 million. The decrease was primarily due to lower average market crack spreads, partially offset by wider WTI-WCS and WTI-WTS differentials, which created a feedstock cost advantage, a reduction in the cost of RINs, higher realized margins on refined products, and improved crude utilization rates at both Refineries. Operating Margin From Continuing Operations Variance 1,018 162 17 149 63 22 135 1,068 58 Three Months Ended December 31, 2017 Upstream Price Upstream Volumes Upstream Realized Risk Royalties Upstream Operating Refining and Marketing Other (1) Management Expenses Operating Margin Three Months Ended December 31, 2018 (1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. Discontinued Operations On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta. As a result, there was no production in the fourth quarter of 2018 compared with 74,109 BOE per day in 2017. Consolidated Results Cash From Operating Activities and Adjusted Funds Flow Total Cash From Operating Activities and Adjusted Funds Flow decreased in the fourth quarter of 2018 compared with 2017, primarily due to lower Operating Margin, as discussed above. The decrease in Cash From Operating Activities was partially offset by changes in non-cash working capital. The change in non-cash working capital in the fourth quarter of 2018 was primarily due to a decrease in accounts receivable and inventory, partially offset by a decrease in accounts payable and income tax payable. For 2017, the change in non-cash working capital was primarily due to an increase in accounts payable and income tax payable, partially offset by an increase in accounts receivable and inventory. Selected Operating and Consolidated Financial Results ($ millions, except per share amounts or where otherwise indicated) 2018 Q3 Q4 Q2 Q1 Q4 Q2 Q1 2017 Q3 Total Production (BOE per day) 432,714 495,608 518,609 488,561 554,606 590,851 436,929 295,414 354,592 408,950 423,340 395,474 422,157 449,055 333,664 234,914 469 520 572 558 795 851 620 363 432,713 495,592 518,530 487,464 480,497 478,817 322,792 184,001 477 502 492 518 464 490 349 369 450 480 462 490 449 476 406 433 4,545 5,857 5,832 4,610 5,079 4,386 4,037 3,541 Total Cash From Operating Activities 485 1,259 533 (123 ) 900 592 1,239 488 1,258 506 (134 ) 833 481 1,102 Total Adjusted Funds Flow (36 ) 977 774 (41 ) 866 980 745 (33 ) 976 747 (53 ) 796 865 603 From Continuing Operations (1,670 ) (41 ) (292 ) (752 ) (533 ) Per Share ($) (3) (1.36 ) (0.03 ) (0.24 ) (0.61 ) (0.43 ) Total Operating Earnings (Loss) (1,672 ) (42 ) (272 ) (743 ) (514 ) (1.36 ) (0.03 ) (0.22 ) (0.60 ) (0.42 ) 240 0.20 327 0.27 298 (39 ) 0.27 (0.05 ) 352 (39 ) 0.32 (0.05 ) From Continuing Operations (1,350 ) (242 ) (410 ) (914 ) (776 ) 275 2,558 (1.10 ) (0.20 ) (0.33 ) (0.74 ) (0.63 ) 0.22 2.30 (1,356 ) (241 ) (418 ) (654 ) 620 (82 ) 2,617 (1.10 ) (0.20 ) (0.34 ) (0.53 ) 0.50 (0.07 ) 2.35 Total Capital Investment 276 271 292 524 583 438 327 276 271 294 522 557 396 277 62 61 62 60 61 62 61 41 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 305 450 195 328 183 323 211 0.25 211 0.25 225 313 and defined in this MD&A. Non-GAAP measure defined in this MD&A. Represented on a basic and diluted per share basis. Includes expenditures on PP&E, E&E assets, and assets held for sale. (2) (3) (4) Fourth Quarter 2018 Results Compared With the Fourth Quarter 2017 Production Volumes Liquids (barrels per day) Natural Gas (MMcf per day) Total Production From Continuing Operations (BOE per day) Refinery Operations Crude Oil Runs (Mbbls/d) Refined Products (Mbbls/d) Revenues Operating Margin (1) Cash From Operating Activities From Continuing Operations Adjusted Funds Flow (2) From Continuing Operations Operating Earnings (Loss) (2) Per Share ($) (3) Net Earnings (Loss) Per Share ($) (3) Total Net Earnings (Loss) Per Share ($) (3) Capital Investment (4) From Continuing Operations Dividends Cash Dividends Per Share ($) Continuing Operations Production Volumes Refinery Operations nameplate capacity. Total production from continuing operations decreased 10 percent in the fourth quarter of 2018 compared with 2017. The decrease in production was primarily due to our decision to manage oil sands production rates in response to takeaway capacity constraints and wider heavy oil differentials. Restricting production well rates reduced oil sands production by approximately 51,000 barrels per day in the fourth quarter of 2018 compared with 2017. Crude oil runs and refined product output increased compared with 2017, with both Refineries operating above Revenues Revenues decreased $534 million in 2018 primarily due to: • Wider light-heavy crude oil differentials resulting in a 71 percent decrease in our liquids sales prices from continuing operations to $13.26 per barrel; and Decreased sales volumes due to lower production. • The decreases above were partially offset by increased refining revenues due to higher realized crack spreads and increased crude utilization rates, higher revenues from third-party crude oil and natural gas sales undertaken by the marketing group, as well as lower crude oil royalties. Operating Margin From Continuing Operations 135 1,191 911 157 1,018 1,097 572 Total Operating Margin 132 1,192 938 169 1,088 1,214 731 • • Operating Margin from continuing operations decreased 87 percent in the fourth quarter of 2018 compared with 2017. Upstream Operating Margin decreased by $820 million due to: • A decrease in our average liquids sales prices due to wider light-heavy crude oil differentials and higher condensate costs; Increased transportation and blending expenses related to an increase in the price of condensate; and Decreased sales volumes due to lower production. These decreases were partially offset by: • • Lower royalties primarily due to a lower realized liquids sales price; and Realized risk management losses of $86 million compared with losses of $235 million in 2017. Refining and Marketing Operating Margin decreased by $63 million. The decrease was primarily due to lower average market crack spreads, partially offset by wider WTI-WCS and WTI-WTS differentials, which created a feedstock cost advantage, a reduction in the cost of RINs, higher realized margins on refined products, and improved crude utilization rates at both Refineries. Operating Margin From Continuing Operations Variance ) s n o i l l i m $ ( 1,018 1,200 1,000 800 600 400 200 0 -200 -400 162 17 149 63 22 135 1,068 58 (1) Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements, in Notes 1 and 9 of the Interim Consolidated Financial Statements Three Months Ended December 31, 2017 Upstream Price Upstream Volumes Upstream Realized Risk Management Royalties Upstream Operating Expenses Refining and Marketing Operating Margin Other (1) Three Months Ended December 31, 2018 (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 On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta. As a result, there was no production in the fourth quarter of 2018 compared with 74,109 BOE per day in 2017. Consolidated Results Cash From Operating Activities and Adjusted Funds Flow Total Cash From Operating Activities and Adjusted Funds Flow decreased in the fourth quarter of 2018 compared with 2017, primarily due to lower Operating Margin, as discussed above. The decrease in Cash From Operating Activities was partially offset by changes in non-cash working capital. The change in non-cash working capital in the fourth quarter of 2018 was primarily due to a decrease in accounts receivable and inventory, partially offset by a decrease in accounts payable and income tax payable. For 2017, the change in non-cash working capital was primarily due to an increase in accounts payable and income tax payable, partially offset by an increase in accounts receivable and inventory. 2018 ANNUAL REPORT | 33 Operating Earnings (Loss) Operating Earnings from continuing operations decreased $1,137 million in the three months ended December 31, 2018 compared with 2017. The decrease was primarily due to exploration expense of $2.1 billion in the fourth quarter of 2018 compared with $887 million in 2017, as well as lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above. These decreases were partially offset by a deferred income tax recovery of $705 million compared with a recovery of $201 million in 2017, a re-measurement gain on the contingent payment of $361 million compared with $29 million in the fourth quarter of 2017, and lower DD&A. Discontinued operations recorded an Operating Loss of $2 million in the fourth quarter of 2018 compared with Operating Earnings of $19 million in the same period of 2017. Net Earnings (Loss) Net loss from continuing operations of $1,350 million for the three months ended December 31, 2018 compared with a net loss of $776 million in 2017. The change was primarily due to lower operating earnings, as discussed above, partially offset by unrealized risk management gains of $741 million compared with losses of $654 million in 2017. In addition, a deferred tax recovery of $275 million was recorded in the fourth quarter of 2017 to reflect the benefit of the decreased U.S. federal corporate income tax rate, and non-operating unrealized foreign exchange losses of $296 million compared with losses of $51 million in 2017. Net earnings from discontinued operations in the fourth quarter of 2017 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 2018 was $276 million, a decrease of $281 million from 2017. The decrease was primarily due to our continued focus on capital discipline and reduced activity in the Deep Basin relative to 2017. Capital investment from discontinued operations was $nil in the fourth quarter of 2018 compared with $26 million in 2017 as a result of the decision to divest our legacy Conventional assets. OIL AND GAS RESERVES Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production. We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy crude oil, light and medium oil, NGLs, conventional natural gas and shale gas proved and probable reserves. For disclosure purposes, we have included heavy crude oil with bitumen and shale gas with conventional natural gas, as the reserves of heavy crude oil and shale gas were not material in 2018, following the divestitures of Suffield on January 5, 2018 and CPP on September 6, 2018. Bitumen (1) (MMbbls) Light and Medium Oil (MMbbls) NGLs (MMbbls) Bitumen (1) (MMbbls) Light and Medium Oil (MMbbls) NGLs (MMbbls) Conventional Natural Gas (2) (Bcf) 4,831 1,598 6,429 12 5 17 72 44 116 1,513 1,041 2,554 Total (MMBOE) 5,167 1,821 6,988 Bitumen (1) (MMbbls) Light and Medium Oil (MMbbls) NGLs (MMbbls) Reserves As at December 31, 2018 (before royalties) Proved Probable Proved plus Probable (1) (2) Includes heavy crude oil reserves that are not material. Includes shale gas reserves that are not material. Reconciliation of Proved Reserves Extensions and Improved Recovery (before royalties) December 31, 2017 Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production (3) December 31, 2018 Year Over Year Change Year Over Year Change (percent) Includes heavy crude oil reserves that are not material. Includes shale gas reserves that are not material. (1) (2) (3) Reconciliation of Proved Plus Probable Reserves Extensions and Improved Recovery (before royalties) December 31, 2017 Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production (3) December 31, 2018 Year Over Year Change Year Over Year Change (percent) Includes heavy crude oil reserves that are not material. Includes shale gas reserves that are not material. (1) (2) (3) 4,765 131 - 81 - - (13 ) (133 ) 4,831 66 1 6,410 105 - 64 - - (17 ) (133 ) 6,429 19 - 13 2 - - - - (1 ) (2 ) 12 (1 ) (8 ) 19 3 - (2 ) - - (1 ) (2 ) 17 (2 ) (11 ) Conventional Natural Gas (2) (Bcf) Total (MMBOE) 103 2,109 5,232 11 - (3 ) - - (30 ) (9 ) 72 (31 ) (30 ) 210 - (29 ) - - (582 ) (195 ) (596 ) (28 ) 179 - 74 - - (141 ) (177 ) (65 ) (1 ) 1,513 5,167 Conventional Natural Gas (2) (Bcf) Total (MMBOE) 171 3,256 7,142 25 - (8 ) - - (63 ) (9 ) 116 (55 ) (32 ) 515 - (138 ) - - (884 ) (195 ) 220 - 32 - - (229 ) (177 ) 2,554 6,988 (702 ) (154 ) (22 ) (2 ) Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production. 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, 2018. 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. Bitumen proved reserves increased by 66 million barrels as additions from the recognition of lower continuous net pay thickness cut-offs in Oil Sands and a minor Alberta Energy Regulator (“AER”) approved area expansion at Foster Creek, as well as improved performance in Oil Sands more than offset reductions due to the divestiture of Suffield (heavy crude oil) and current year production; Bitumen proved plus probable reserves increased by 19 million barrels as additions due to the recognition of lower continuous net pay thickness cut-offs and improved performance in Oil Sands were partially offset by reductions due to the divestiture of Suffield (heavy crude oil) and current year production; Light and medium oil proved reserves and proved plus probable reserves decreased by one million barrels and two million barrels, respectively, as minor additions were more than offset by reductions due to the divestiture of CPP and current year production; NGLs proved and proved plus probable reserves decreased by 31 million barrels and 55 million barrels, respectively, as additions attributed to Deep Basin development were more than offset by reductions due to the divestiture of CPP, technical revisions attributed to changes to future Deep Basin development plans, and current year production; and Conventional natural gas proved and proved plus probable reserves decreased by 596 billion cubic feet and 702 billion cubic feet, respectively, as additions attributed to Deep Basin development were more than offset by reductions due to the divestiture of CPP, technical revisions attributed to changes to the Deep Basin development plans, and current year production. Developments in 2018 compared with 2017 include: • • • • • The reserves data that follows is presented as at December 31, 2018 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 costs are dated January 1, 2019. Comparative information as at December 31, 2017 uses the January 1, 2018 IQRE Average Forecast prices and costs. 34 | CENOVUS ENERGY Operating Earnings (Loss) Operating Earnings from continuing operations decreased $1,137 million in the three months ended December 31, 2018 compared with 2017. The decrease was primarily due to exploration expense of $2.1 billion in the fourth quarter of 2018 compared with $887 million in 2017, as well as lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above. These decreases were partially offset by a deferred income tax recovery of $705 million compared with a recovery of $201 million in 2017, a re-measurement gain on the contingent payment of $361 million compared with $29 million in the fourth quarter of 2017, and lower DD&A. Discontinued operations recorded an Operating Loss of $2 million in the fourth quarter of 2018 compared with Operating Earnings of $19 million in the same period of 2017. Net Earnings (Loss) Net loss from continuing operations of $1,350 million for the three months ended December 31, 2018 compared with a net loss of $776 million in 2017. The change was primarily due to lower operating earnings, as discussed above, partially offset by unrealized risk management gains of $741 million compared with losses of $654 million in 2017. In addition, a deferred tax recovery of $275 million was recorded in the fourth quarter of 2017 to reflect the benefit of the decreased U.S. federal corporate income tax rate, and non-operating unrealized foreign exchange losses of $296 million compared with losses of $51 million in 2017. Net earnings from discontinued operations in the fourth quarter of 2017 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 2018 was $276 million, a decrease of $281 million from 2017. The decrease was primarily due to our continued focus on capital discipline and reduced activity in the Deep Basin relative to 2017. Capital investment from discontinued operations was $nil in the fourth quarter of 2018 compared with $26 million in 2017 as a result of the decision to divest our legacy Conventional assets. OIL AND GAS RESERVES We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy crude oil, light and medium oil, NGLs, conventional natural gas and shale gas proved and probable reserves. For disclosure purposes, we have included heavy crude oil with bitumen and shale gas with conventional natural gas, as the reserves of heavy crude oil and shale gas were not material in 2018, following the divestitures of Suffield on January 5, 2018 and CPP on September 6, 2018. Developments in 2018 compared with 2017 include: • • • • • Bitumen proved reserves increased by 66 million barrels as additions from the recognition of lower continuous net pay thickness cut-offs in Oil Sands and a minor Alberta Energy Regulator (“AER”) approved area expansion at Foster Creek, as well as improved performance in Oil Sands more than offset reductions due to the divestiture of Suffield (heavy crude oil) and current year production; Bitumen proved plus probable reserves increased by 19 million barrels as additions due to the recognition of lower continuous net pay thickness cut-offs and improved performance in Oil Sands were partially offset by reductions due to the divestiture of Suffield (heavy crude oil) and current year production; Light and medium oil proved reserves and proved plus probable reserves decreased by one million barrels and two million barrels, respectively, as minor additions were more than offset by reductions due to the divestiture of CPP and current year production; NGLs proved and proved plus probable reserves decreased by 31 million barrels and 55 million barrels, respectively, as additions attributed to Deep Basin development were more than offset by reductions due to the divestiture of CPP, technical revisions attributed to changes to future Deep Basin development plans, and current year production; and Conventional natural gas proved and proved plus probable reserves decreased by 596 billion cubic feet and 702 billion cubic feet, respectively, as additions attributed to Deep Basin development were more than offset by reductions due to the divestiture of CPP, technical revisions attributed to changes to the Deep Basin development plans, and current year production. The reserves data that follows is presented as at December 31, 2018 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 costs are dated January 1, 2019. Comparative information as at December 31, 2017 uses the January 1, 2018 IQRE Average Forecast prices and costs. Reserves As at December 31, 2018 (before royalties) Proved Probable Proved plus Probable Bitumen (1) (MMbbls) Light and Medium Oil (MMbbls) NGLs (MMbbls) Conventional Natural Gas (2) (Bcf) 4,831 1,598 6,429 12 5 17 72 44 116 1,513 1,041 2,554 Total (MMBOE) 5,167 1,821 6,988 (1) (2) Includes heavy crude oil reserves that are not material. Includes shale gas reserves that are not material. Reconciliation of Proved Reserves (before royalties) December 31, 2017 Extensions and Improved Recovery Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production (3) December 31, 2018 Year Over Year Change Year Over Year Change (percent) Bitumen (1) (MMbbls) Light and Medium Oil (MMbbls) 4,765 131 - 81 - - (13 ) (133 ) 4,831 66 1 13 2 - - - - (1 ) (2 ) 12 (1 ) (8 ) Conventional Natural Gas (2) (Bcf) Total (MMBOE) 2,109 5,232 210 - (29 ) - - (582 ) (195 ) 179 - 74 - - (141 ) (177 ) 1,513 5,167 (596 ) (28 ) (65 ) (1 ) NGLs (MMbbls) 103 11 - (3 ) - - (30 ) (9 ) 72 (31 ) (30 ) (1) (2) (3) Includes heavy crude oil reserves that are not material. Includes shale gas reserves that are not material. Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production. Reconciliation of Proved Plus Probable Reserves (before royalties) December 31, 2017 Extensions and Improved Recovery Discoveries Technical Revisions Economic Factors Acquisitions Dispositions Production (3) December 31, 2018 Year Over Year Change Year Over Year Change (percent) Bitumen (1) (MMbbls) Light and Medium Oil (MMbbls) 6,410 105 - 64 - - (17 ) (133 ) 6,429 19 - 19 3 - (2 ) - - (1 ) (2 ) 17 (2 ) (11 ) Conventional Natural Gas (2) (Bcf) NGLs (MMbbls) 171 Total (MMBOE) 7,142 220 - 32 - - (229 ) (177 ) 3,256 515 - (138 ) - - (884 ) (195 ) 2,554 6,988 (702 ) (154 ) (22 ) (2 ) 25 - (8 ) - - (63 ) (9 ) 116 (55 ) (32 ) (1) (2) (3) Includes heavy crude oil reserves that are not material. Includes shale gas reserves that are not material. Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production. 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, 2018. 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. 2018 ANNUAL REPORT | 35 LIQUIDITY AND CAPITAL RESOURCES The following sources of liquidity are available at December 31, 2018: ($ 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 2018 2017 2016 2,118 36 2,154 (1,017 ) 404 (613 ) 1,541 (1,410 ) 2,611 448 3,059 (15,859 ) 2,993 (12,866 ) (9,807 ) 6,515 40 171 182 (3,110 ) 2018 781 4,500 2017 610 4,500 426 435 861 (911 ) (168 ) (1,079 ) (218 ) (168 ) 1 (385 ) 2016 3,720 4,000 Cash from operating activities decreased in 2018 mainly due to lower Operating Margin, as discussed in the Financial Results section of this MD&A, a decrease in current income tax recovery and higher general and administrative costs, primarily due to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of $56 million related to the Acquisition. These decreases were partially offset by changes in non-cash working capital, as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held for sale, the current portion of the contingent payment, and onerous contract provisions, our working capital was $500 million at December 31, 2018 compared with $1,141 million at December 31, 2017. Working capital declined primarily due to the current portion of the $682 million of unsecured notes due on October 15, 2019. The decline in working capital was also due to lower accounts receivable and inventory, partially offset by a decrease in accounts payable. We anticipate that we will continue to meet our payment obligations as they come due. Cash From (Used In) Investing Activities Cash used in investing activities was lower in 2018 primarily due to the Acquisition in 2017. Cash From (Used In) Financing Activities In 2018, cash was used in financing activities primarily for the repayment of $1.1 billion of debt, as well as dividends paid on common shares. In 2017, cash was generated by financing activities from the issuance of debt and common shares to finance the Acquisition. In 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due on October 15, 2019. We also paid US$69 million to repurchase a portion of our unsecured notes with a principal of US$76 million. As at December 31, 2018 we had US$6,774 million in U.S. dollar debt ($9,241 million) compared with US$7,650 million ($9,597 million) at December 31, 2017. As at December 31, 2018, we were in compliance with all of the terms of our debt agreements. Dividends In 2018, we paid dividends of $0.20 per common share or $245 million (2017 – 0.20 per common share or $225 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly. Available Sources of Liquidity We expect cash flows from our upstream and refining operations to fund all of our cash requirements in 2019. Any potential shortfalls may be funded through prudent use of our balance sheet capacity including draws on our credit facility, management of our asset portfolio and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and Fitch Ratings. 36 | CENOVUS ENERGY Term Amount Not applicable November 2022 November 2021 781 3,300 1,200 ($ millions) Cash and Cash Equivalents Committed Credit Facility – Tranche A Committed Credit Facility – Tranche B Committed Credit Facility Base Shelf Prospectus subject to market conditions. Financial Metrics We have a committed credit facility in place that consists of a $1.2 billion tranche and $3.3 billion tranche. In the fourth quarter of 2018, we amended the committed credit facility to extend the maturity date of the $1.2 billion tranche to November 30, 2021 and the $3.3 billion tranche to November 30, 2022. As of December 31, 2018, no amounts were drawn on our committed credit facility. Cenovus has in place a base shelf prospectus which expires in November 2019. As at December 31, 2018, US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are 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, E&E Write-down, 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, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. Our objective is to maintain a high level of capital discipline and manage our 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 our 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. We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenants 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, Current Portion of Long-Term Debt Long-Term Debt Less: Cash and Cash Equivalents Net Debt Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income DD&A E&E Write-down 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 (1) Calculated on a trailing 12-month basis. Includes discontinued operations. 2018 682 8,482 (781 ) 8,383 2017 - 9,513 (610 ) 8,903 2016 - 6,332 (3,720 ) 2,612 (2,669 ) 3,366 (545 ) 628 (19 ) (920 ) 2,131 2,123 (1,249 ) 854 - 50 (301 ) 795 (12 ) 725 (62 ) 352 2,030 890 729 (812 ) (2,555 ) (138 ) (1,285 ) 1 (5 ) 492 (52 ) (382 ) 1,498 2 554 (198 ) - - - 6 34 1,409 1,411 3,236 5.9x 2.8x 1.9x LIQUIDITY AND CAPITAL RESOURCES The following sources of liquidity are available at December 31, 2018: ($ 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 2018 2017 2016 2,118 36 2,154 (1,017 ) 404 (613 ) 1,541 (1,410 ) 2,611 448 3,059 (15,859 ) 2,993 (12,866 ) (9,807 ) 6,515 40 171 182 (3,110 ) 2018 781 4,500 2017 610 4,500 426 435 861 (911 ) (168 ) (1,079 ) (218 ) (168 ) 1 (385 ) 2016 3,720 4,000 Cash from operating activities decreased in 2018 mainly due to lower Operating Margin, as discussed in the Financial Results section of this MD&A, a decrease in current income tax recovery and higher general and administrative costs, primarily due to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of $56 million related to the Acquisition. These decreases were partially offset by changes in non-cash working capital, as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held for sale, the current portion of the contingent payment, and onerous contract provisions, our working capital was $500 million at December 31, 2018 compared with $1,141 million at December 31, 2017. Working capital declined primarily due to the current portion of the $682 million of unsecured notes due on October 15, 2019. The decline in working capital was also due to lower accounts receivable and inventory, partially offset by a decrease in accounts payable. We anticipate that we will continue to meet our payment obligations as they come due. Cash From (Used In) Investing Activities Cash used in investing activities was lower in 2018 primarily due to the Acquisition in 2017. Cash From (Used In) Financing Activities In 2018, cash was used in financing activities primarily for the repayment of $1.1 billion of debt, as well as dividends paid on common shares. In 2017, cash was generated by financing activities from the issuance of debt and common shares to finance the Acquisition. In 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due on October 15, 2019. We also paid US$69 million to repurchase a portion of our unsecured notes with a principal of US$76 million. As at December 31, 2018 we had US$6,774 million in U.S. dollar debt ($9,241 million) compared with US$7,650 million ($9,597 million) at December 31, 2017. As at December 31, 2018, we were in compliance with all of the terms of our debt agreements. In 2018, we paid dividends of $0.20 per common share or $245 million (2017 – 0.20 per common share or $225 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly. Dividends Available Sources of Liquidity We expect cash flows from our upstream and refining operations to fund all of our cash requirements in 2019. Any potential shortfalls may be funded through prudent use of our balance sheet capacity including draws on our credit facility, management of our asset portfolio and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and Fitch Ratings. ($ millions) Cash and Cash Equivalents Committed Credit Facility – Tranche A Committed Credit Facility – Tranche B Committed Credit Facility Term Not applicable November 2022 November 2021 Amount 781 3,300 1,200 We have a committed credit facility in place that consists of a $1.2 billion tranche and $3.3 billion tranche. In the fourth quarter of 2018, we amended the committed credit facility to extend the maturity date of the $1.2 billion tranche to November 30, 2021 and the $3.3 billion tranche to November 30, 2022. As of December 31, 2018, no amounts were drawn on our committed credit facility. Base Shelf Prospectus Cenovus has in place a base shelf prospectus which expires in November 2019. As at December 31, 2018, US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions. 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, E&E Write-down, 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, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. Our objective is to maintain a high level of capital discipline and manage our 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 our 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. We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenants 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, Current Portion of Long-Term Debt 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 Write-down 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 (1) Calculated on a trailing 12-month basis. Includes discontinued operations. 2018 682 8,482 (781 ) 8,383 2017 - 9,513 (610 ) 8,903 2016 - 6,332 (3,720 ) 2,612 (2,669 ) 3,366 (545 ) 628 (19 ) (920 ) 2,131 2,123 (1,249 ) 854 - 50 (301 ) 795 (12 ) 1,411 725 (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 5.9x 2.8x 1.9x 2018 ANNUAL REPORT | 37 ($ millions) Operating Transportation and Storage (1) Operating Leases (Building Leases) (2) Other Long-term Commitments Interest on Long-term Debt Decommissioning Liabilities Total Operating Investing Capital Commitments Contingent Payment Total Investing Financing Other Total Financing Total Payments (3) Long-term Debt (principal only) 156 148 470 56 21 15 36 682 - 682 2019 2020 2021 2022 2023 Thereafter Total Expected Payment Date 1,040 1,104 1,335 1,491 1,562 16,809 23,341 150 146 144 141 2,158 2,895 81 45 37 32 147 490 431 431 431 411 5,993 8,167 57 34 39 42 2,402 2,630 1,870 1,823 1,991 2,142 2,188 27,509 37,523 2 47 49 - - - 1 66 67 - 1 1 - 15 15 - - - - - - 24 143 167 682 614 7,263 9,241 - 1 2 4 682 615 7,265 9,245 Includes transportation commitments of $14 billion that are subject to regulatory approval or have been approved but are not yet in service. (1) (2) (3) Includes onerous contract provisions. Contracts on behalf of WRB are reflected at our 50 percent interest. 2,588 1,872 2,059 2,839 2,803 34,774 46,935 We have total commitments not included on our balance sheet of $26 billion, of which $23 billion are for various transportation commitments, including $5 billion in new contracts primarily related to Keystone XL, expanded freight and rail terminal and tank contracts. Transportation commitments include $14 billion that are subject to regulatory approval or have been approved but are not yet in service (December 31, 2017 – $9 billion). These agreements are for terms up to 20 years subsequent to the date of commencement and should help align our future transportation requirements with anticipated production growth. 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, 2018, there were outstanding letters of credit aggregating $336 million issued as security for performance under certain contracts (December 31, 2017 – $376 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, 2018, the estimated fair value of the contingent payment was $132 million. See the Corporate and Eliminations section of this MD&A for more details. Net Debt to Capitalization is calculated as follows: As at December 31, Net Debt Shareholders’ Equity Capitalization Net Debt to Capitalization (1) (percent) 2018 2017 8,383 17,468 25,851 8,903 19,981 28,884 2016 2,612 11,590 14,202 32 31 18 (1) Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity. As at December 31, 2018, Cenovus’s Net Debt to Adjusted EBITDA is 5.9x, which is above our target. Net debt to Adjusted EBITDA increased as result of lower Adjusted EBITDA due to reasons mentioned in the Financial Results section of this MD&A. This was partially offset by the reduction in our debt levels. On October 29, 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due October 15, 2019. In December 2018, we also paid US$69 million to repurchase our unsecured notes with a principal amount of US$76 million. Subsequent to December 31, 2018, we repurchased a further US$324 million of unsecured notes for cash of US$300 million. 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. Additional information regarding our financial measures and capital structure can be found in the notes to the Consolidated Financial Statements. Share Capital and Stock-Based Compensation Plans As at December 31, 2018, there were approximately 1,229 million common shares outstanding (2017 – 1,229 million common shares). In the second quarter of 2017, Cenovus closed a bought-deal common share financing of 187.5 million common shares, for gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs). In addition, Cenovus 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. In accordance with these agreements, ConocoPhillips has certain rights and restrictions, including, among other things, the ability to nominate new members to the Board and the requirement to 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, 2018, ConocoPhillips continued to hold these common 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 30 of the Consolidated Financial Statements for more details on our Stock Option Plan and our Performance Share Unit, Restricted Share Unit and Deferred Share Unit Plans. As at January 31, 2019 Common Shares Stock Options Other Stock-Based Compensation Plans Contractual Obligations and Commitments Units Outstanding (thousands) 1,228,790 33,957 15,034 Units Exercisable (thousands) N/A 27,083 1,558 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. 38 | CENOVUS ENERGY Net Debt to Capitalization is calculated as follows: As at December 31, Net Debt Shareholders’ Equity Capitalization Net Debt to Capitalization (1) (percent) (1) Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity. 2018 2017 8,383 17,468 25,851 8,903 19,981 28,884 2016 2,612 11,590 14,202 32 31 18 As at December 31, 2018, Cenovus’s Net Debt to Adjusted EBITDA is 5.9x, which is above our target. Net debt to Adjusted EBITDA increased as result of lower Adjusted EBITDA due to reasons mentioned in the Financial Results section of this MD&A. This was partially offset by the reduction in our debt levels. On October 29, 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due October 15, 2019. In December 2018, we also paid US$69 million to repurchase our unsecured notes with a principal amount of US$76 million. Subsequent to December 31, 2018, we repurchased a further US$324 million of unsecured notes for cash of US$300 million. 65 percent; we are well below this limit. Consolidated Financial Statements. Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed Additional information regarding our financial measures and capital structure can be found in the notes to the Share Capital and Stock-Based Compensation Plans As at December 31, 2018, there were approximately 1,229 million common shares outstanding (2017 – 1,229 million common shares). In the second quarter of 2017, Cenovus closed a bought-deal common share financing of 187.5 million common shares, for gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs). In addition, Cenovus 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. In accordance with these agreements, ConocoPhillips has certain rights and restrictions, including, among other things, the ability to nominate new members to the Board and the requirement to 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, 2018, ConocoPhillips continued to hold these common 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 30 of the Consolidated Financial Statements for more details on our Stock Option Plan and our Performance Share Unit, Restricted Share Unit and Deferred Share Unit Plans. As at January 31, 2019 Common Shares Stock Options Other Stock-Based Compensation Plans Contractual Obligations and Commitments Units Units Outstanding (thousands) Exercisable (thousands) 1,228,790 33,957 15,034 N/A 27,083 1,558 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. ($ millions) Operating Transportation and Storage (1) Operating Leases (Building Leases) (2) Other Long-term Commitments Interest on Long-term Debt Decommissioning Liabilities Total Operating Investing Capital Commitments Contingent Payment Total Investing Financing Long-term Debt (principal only) Other Total Financing Total Payments (3) 2019 2020 2021 2022 2023 Thereafter Total Expected Payment Date 1,040 156 148 470 56 1,870 21 15 36 682 - 682 2,588 1,104 1,335 146 150 1,491 1,562 16,809 23,341 2,158 2,895 141 144 81 431 57 45 431 34 37 431 39 32 411 147 490 5,993 8,167 42 2,402 2,630 1,823 1,991 2,142 2,188 27,509 37,523 2 47 49 - - - 1 66 67 - 1 1 - 15 15 - - - - - - 24 143 167 682 614 7,263 9,241 - 1 2 4 682 615 7,265 9,245 1,872 2,059 2,839 2,803 34,774 46,935 (1) (2) (3) Includes transportation commitments of $14 billion that are subject to regulatory approval or have been approved but are not yet in service. Includes onerous contract provisions. Contracts on behalf of WRB are reflected at our 50 percent interest. We have total commitments not included on our balance sheet of $26 billion, of which $23 billion are for various transportation commitments, including $5 billion in new contracts primarily related to Keystone XL, expanded freight and rail terminal and tank contracts. Transportation commitments include $14 billion that are subject to regulatory approval or have been approved but are not yet in service (December 31, 2017 – $9 billion). These agreements are for terms up to 20 years subsequent to the date of commencement and should help align our future transportation requirements with anticipated production growth. 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, 2018, there were outstanding letters of credit aggregating $336 million issued as security for performance under certain contracts (December 31, 2017 – $376 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, 2018, the estimated fair value of the contingent payment was $132 million. See the Corporate and Eliminations section of this MD&A for more details. 2018 ANNUAL REPORT | 39 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 Standards, 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 Guidelines (2017). The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as through regular 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. 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. In addition, we identify risks related to our ability to pay a dividend to shareholders; and risks related to internal controls for financial reporting. Changes in financial management and/or market conditions could impact a number of factors including, but not limited to, Cenovus’s cash flows, financial condition, results of operations and growth, the maintenance of our existing operations and business plans, 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; actions by the Government of Alberta including, without limitation, imposing, amending, or lifting crude oil production curtailments, and compliance or non-compliance with imposed crude oil production curtailments; 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. 40 | CENOVUS ENERGY 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 (independent of any crude oil production curtailment mandated by the Government of Alberta and then in effect), 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, crude oil differentials, diluent or condensate supply prices and differentials, 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 costs or sales of our production. 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, 33 and 34 to the Consolidated Financial Statements. 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 Standards, 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 Guidelines (2017). The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as through regular 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. 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. In addition, we identify risks related to our ability to pay a dividend to shareholders; and risks related to internal controls for financial reporting. Changes in financial management and/or market conditions could impact a number of factors including, but not limited to, Cenovus’s cash flows, financial condition, results of operations and growth, the maintenance of our existing operations and business plans, 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; actions by the Government of Alberta including, without limitation, imposing, amending, or lifting crude oil production curtailments, and compliance or non-compliance with imposed crude oil production curtailments; 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 (independent of any crude oil production curtailment mandated by the Government of Alberta and then in effect), 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, crude oil differentials, diluent or condensate supply prices and differentials, 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 costs or sales of our production. 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, 33 and 34 to the Consolidated Financial Statements. 2018 ANNUAL REPORT | 41 Impact of Financial Risk Management Activities ($ millions) Crude Oil (1) Refining Interest Rate Foreign Exchange (Gain) Loss on Risk Management Income Tax Expense (Recovery) (Gain) Loss on Risk Management, After Tax 2018 Realized Unrealized 1,577 (1 ) (1,219 ) (5 ) (23 ) 1 1,554 (422 ) 1,132 (26 ) 1 (1,249 ) 336 (913 ) Total 358 (6 ) (49 ) 2 305 (86 ) 219 2017 Realized Unrealized 307 6 - (146 ) 167 (60 ) 107 716 - 13 - 729 (197 ) 532 Total 1,023 6 13 (146 ) 896 (257 ) 639 (1) 2017 excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment, which have been classified as a discontinued operation. In 2018, we incurred realized losses on crude oil risk management activities as the settlement prices exceeded our contract prices. The majority of these hedging contracts were established to provide downside protection and support financial resilience following the Acquisition. These hedging contracts have now expired. Unrealized gains were recorded on our crude oil financial instruments in the twelve months ended December 31, 2018 primarily due to the realization of settled positions, while partially offset by losses due to WTI and Brent benchmark price increases. Sensitivities – Risk Management Positions The following table summarizes the sensitivities of the fair value of our risk management positions to independent fluctuations in commodity prices, interest rates, and foreign exchange 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, 2018 could have resulted in unrealized gains (losses) for the year as follows: Crude Oil Commodity Price Crude Oil Differential Price Interest Rate Swaps ± US$5.00 per bbl Applied to WTI and Condensate Hedges ± US$2.50 per bbl Applied to Differential Hedges Tied to Production ± 50 Basis Points Foreign Exchange ± $0.05 U.S. per Canadian Dollar Foreign Exchange Rate Sensitivity Range (78 ) 4 12 4 Increase Decrease 80 (4 ) (13 ) (4 ) Interest Rates For further information on our risk management positions, see Notes 33 and 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 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. 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. 42 | CENOVUS ENERGY We are required to comply with various financial and operating covenants under our credit facility 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 credit 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. We may periodically enter into transactions to manage our exposure to exchange rate fluctuations. Exchange rate fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows. 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. We may periodically enter into transactions to manage our exposure to interest rate fluctuations. 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, satisfying solvency testing, 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 Risk 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 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. Impact of Financial Risk Management Activities ($ millions) Crude Oil (1) Refining Interest Rate Foreign Exchange 2018 2017 Realized Unrealized Total Realized Unrealized Total 1,577 (1,219 ) 307 716 1,023 (1 ) (23 ) 1 (5 ) (26 ) 1 1,554 (1,249 ) (422 ) 336 358 (6 ) (49 ) 2 305 (86 ) 219 6 - (146 ) 167 (60 ) 107 - 13 - 729 (197 ) 532 6 13 (146 ) 896 (257 ) 639 (Gain) Loss on Risk Management Income Tax Expense (Recovery) (Gain) Loss on Risk Management, After Tax 1,132 (913 ) (1) 2017 excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment, which have been classified as a discontinued operation. In 2018, we incurred realized losses on crude oil risk management activities as the settlement prices exceeded our contract prices. The majority of these hedging contracts were established to provide downside protection and support financial resilience following the Acquisition. These hedging contracts have now expired. Unrealized gains were recorded on our crude oil financial instruments in the twelve months ended December 31, 2018 primarily due to the realization of settled positions, while partially offset by losses due to WTI and Brent benchmark price increases. Sensitivities – Risk Management Positions The following table summarizes the sensitivities of the fair value of our risk management positions to independent fluctuations in commodity prices, interest rates, and foreign exchange 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, 2018 could have resulted in unrealized gains (losses) for the year as follows: Crude Oil Commodity Price ± US$5.00 per bbl Applied to 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 Foreign Exchange ± $0.05 U.S. per Canadian Dollar Foreign Exchange Rate (78 ) 4 12 4 80 (4 ) (13 ) (4 ) Sensitivity Range Increase Decrease For further information on our risk management positions, see Notes 33 and 34 to the Consolidated Financial Statements. Risks Associated with Derivative Financial Instruments netting arrangements, as outlined in our Credit Policy. Exposure to Counterparties 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 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 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. 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 facility 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 credit 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. We may periodically enter into transactions to manage our exposure to exchange rate fluctuations. 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. We may periodically enter into transactions to manage our exposure to interest rate fluctuations. 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, satisfying solvency testing, 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 Risk 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 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. 2018 ANNUAL REPORT | 43 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, any of which may have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation. 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 also 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 availability, 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 by rail to be replaced with newer 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 through British Columbia. 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. 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 44 | CENOVUS ENERGY 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 environmental regulations and 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, developing and producing 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 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 reserves. Cost Management 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. 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. 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, any of which may have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation. 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 also 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 availability, 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 by rail to be replaced with newer 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 through British Columbia. 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. 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 environmental regulations and 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, developing and producing 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. 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. 2018 ANNUAL REPORT | 45 Project Execution Litigation 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; our ability to obtain favourable terms or to be granted access within land-use agreements; 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. If we are unable to retain critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our financial condition, results of operations and pace of growth. 46 | CENOVUS ENERGY 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. 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. Project Execution Litigation 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; our ability to obtain favourable terms or to be granted access within land-use agreements; 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. If we are unable to retain critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our financial condition, results of operations and pace of growth. 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. 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. 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. 2018 ANNUAL REPORT | 47 Abandonment and Reclamation Cost Risk As a general rule, the current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta limits each party's liability to its proportionate ownership of an asset. In the case where one joint owner of an oil and gas asset becomes insolvent and is unable to fund its required A&R activities associated with such asset, 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. On January 31, 2019, the Supreme Court of Canada released its decision in the case of Redwater Energy Corporation (“Redwater”). Reversing the lower court decisions, the Supreme Court of Canada held that the AER may use the provincial legislative scheme to prevent a trustee in bankruptcy from renouncing a debtor’s uneconomic oil and gas assets and require a trustee to satisfy certain environmental obligations in priority to the claims of secured and unsecured creditors. While it is not yet clear how market participants will respond to the Supreme Court of Canada’s decision in Redwater, the decision is anticipated to reduce the availability and increase the cost of credit for borrowers with relatively high levels of A&R obligations within their asset bases, thereby negatively affecting the financial capacity of such borrowers, including potential counterparties to Cenovus, result in additional or more stringent A&R related covenants being imposed on borrowers, and result in increased scrutiny of oil and gas assets and associated A&R liabilities. Following the lower court decisions in Redwater, changes were made to the regulatory regimes in Alberta and British Columbia. 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 (“Directive 067”). Among other things, Directive 067 provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that it should not be eligible to hold AER licences. The Government of British Columbia has announced similar policies and the British Columbia Oil and Gas Commission is exploring the development of a comprehensive liability management strategy, driven in part by the proliferation of orphan assets. 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. The aggregate value of the A&R liabilities assumed by the OWA has increased in recent years following the lower court decisions in Redwater and as a result of the current economic environment. To the extent the Supreme Court of Canada’s decision in Redwater makes the transfer of oil and gas assets from insolvent parties more challenging because a trustee in bankruptcy is unable to separate economic assets from uneconomic assets within the insolvent party’s estate in order to facilitate a sale process, the result could be additional assets being placed upon the OWA. While the Supreme Court of Canada’s decision in Redwater may reduce the A&R liabilities assumed by the OWA in the long-term, the OWA's A&R liabilities will remain at elevated levels until a significant number of orphaned wells are decommissioned by the OWA. As a result, the OWA may seek additional 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 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 new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”) which applies to all conventional wells spud on or after January 1, 2017. The MRF 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 July 13, 2016 and January 1, 2017 may elect to opt-in to the MRF if certain criteria are met. After December 31, 2026, all wells will be subject to the MRF. As part of the MRF, the Government of Alberta 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 48 | CENOVUS ENERGY 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. 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, costs, 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 requires significant expenditures. Our future capital expenditures and operating expenses could continue to increase as a result of, among other things, developments in our business, operations, plans and objectives and changes to existing, or implementation of new, environmental regulations. Failure to comply with environmental regulations may result in, among other things, the imposition of fines, penalties, environmental protection orders, suspension of operations, and could adversely effect 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 effect on our business, financial condition, results of operations and cash flows. 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”). In 2018, the federal government finalized the Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which specifies (i) a carbon price on fossil fuels of $20 per tonne of carbon dioxide equivalent (“CO2e”) in 2019, 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 federal carbon pricing system will apply only in jurisdictions that do not have equivalent measures in place. 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 from the oil and gas sector. The Government of British Columbia has also introduced measures to reduce upstream Abandonment and Reclamation Cost Risk As a general rule, the current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta limits each party's liability to its proportionate ownership of an asset. In the case where one joint owner of an oil and gas asset becomes insolvent and is unable to fund its required A&R activities associated with such asset, 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. On January 31, 2019, the Supreme Court of Canada released its decision in the case of Redwater Energy Corporation (“Redwater”). Reversing the lower court decisions, the Supreme Court of Canada held that the AER may use the provincial legislative scheme to prevent a trustee in bankruptcy from renouncing a debtor’s uneconomic oil and gas assets and require a trustee to satisfy certain environmental obligations in priority to the claims of secured and unsecured creditors. While it is not yet clear how market participants will respond to the Supreme Court of Canada’s decision in Redwater, the decision is anticipated to reduce the availability and increase the cost of credit for borrowers with relatively high levels of A&R obligations within their asset bases, thereby negatively affecting the financial capacity of such borrowers, including potential counterparties to Cenovus, result in additional or more stringent A&R related covenants being imposed on borrowers, and result in increased scrutiny of oil and gas assets and associated A&R liabilities. Following the lower court decisions in Redwater, changes were made to the regulatory regimes in Alberta and British Columbia. 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 (“Directive 067”). Among other things, Directive 067 provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that it should not be eligible to hold AER licences. The Government of British Columbia has announced similar policies and the British Columbia Oil and Gas Commission is exploring the development of a comprehensive liability management strategy, driven in part by the proliferation of orphan assets. 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. The aggregate value of the A&R liabilities assumed by the OWA has increased in recent years following the lower court decisions in Redwater and as a result of the current economic environment. To the extent the Supreme Court of Canada’s decision in Redwater makes the transfer of oil and gas assets from insolvent parties more challenging because a trustee in bankruptcy is unable to separate economic assets from uneconomic assets within the insolvent party’s estate in order to facilitate a sale process, the result could be additional assets being placed upon the OWA. While the Supreme Court of Canada’s decision in Redwater may reduce the A&R liabilities assumed by the OWA in the long-term, the OWA's A&R liabilities will remain at elevated levels until a significant number of orphaned wells are decommissioned by the OWA. As a result, the OWA may seek additional 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 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 new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”) which applies to all conventional wells spud on or after January 1, 2017. The MRF 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 July 13, 2016 and January 1, 2017 may elect to opt-in to the MRF if certain criteria are met. After December 31, 2026, all wells will be subject to the MRF. As part of the MRF, the Government of Alberta 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. 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, costs, 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 requires significant expenditures. Our future capital expenditures and operating expenses could continue to increase as a result of, among other things, developments in our business, operations, plans and objectives and changes to existing, or implementation of new, environmental regulations. Failure to comply with environmental regulations may result in, among other things, the imposition of fines, penalties, environmental protection orders, suspension of operations, and could adversely effect 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 effect on our business, financial condition, results of operations and cash flows. 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”). In 2018, the federal government finalized the Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which specifies (i) a carbon price on fossil fuels of $20 per tonne of carbon dioxide equivalent (“CO2e”) in 2019, 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 federal carbon pricing system will apply only in jurisdictions that do not have equivalent measures in place. 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 from the oil and gas sector. The Government of British Columbia has also introduced measures to reduce upstream 2018 ANNUAL REPORT | 49 methane emissions by 45 percent and establish separate sector-level benchmarks to reduce carbon tax costs for industrial facilities. In 2018, the federal government finalized 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 and British Columbia have developed 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 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. The extent and magnitude of any adverse impacts of current or additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time, in part 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. There is also risk that we could face claims initiated by third parties relating to climate change or other environmental regulations. These claims could, among other things, result in litigation targeted against Cenovus and the oil and gas industry generally, and should any such litigation claims arise, they may have a material adverse effect on our business. Low Carbon Fuel Standards Existing and proposed environmental legislation and regulation 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. Environment and Climate Change Canada has published a regulatory framework on its proposed clean fuel standard regulation to be adopted under the Canadian Environmental Protection Act, 1999. 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 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 states of California and Oregon, and the province of British Columbia have implemented the Low Carbon Fuel Standard, the Clean Fuels Program, 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, importers, and fuel distributors in these jurisdictions 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 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. The IMO’s goal is to significantly reduce the amount of sulphur oxide emanating from ships and it 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 ability of ship owners to install scrubbers, worldwide heavy sour crude production and additional heavy processing availability. 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 or activity in areas identified as critical habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal government in relation to their obligations under 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, a suite of initiatives have been undertaken to support caribou recovery, including: a) the Alberta Caribou Action and Range Planning Project to develop long term habitat management plans such that ranges may return to self-sustaining status, b) development of methods for long term Regional Access Management Plans c) mineral development deferral agreements, and, d) negotiation of conservation agreements under Section 11 of the Species at Risk Act, which seek to codify concrete measures to support the conservation of the species and the protection of its critical habitat. If plans and actions undertaken 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. For example, the federal government is undertaking an imminent threat assessment for a portion of caribou herd range in West Central Alberta which may compel further intervention (this range does not overlap Cenovus’s lands or operations), a habitat protection order under Section 58 of the Species at Risk Act is pending for federally administered lands (including the Saskatchewan side of the Cold Lake Air Weapons Range to the east of Cenovus operations), and is the subject of an application for a protection order for the critical habitat of five sub- populations of woodland caribou. On January 24, 2019, the Athabasca Chipewyan and Mikisew Cree First Nations in northern Alberta, together with the Alberta Wilderness Association and the David Suzuki Foundation, filed an application for judicial review in federal court arguing that the Minister has failed to protect the habitat of five boreal woodland caribou herds. The applicants claim that although the Minister acknowledges that provincial recovery plans for the threatened species are inadequate, the federal government has not fulfilled its duty to issue a protective order under the Species at Risk Act. 50 | CENOVUS ENERGY methane emissions by 45 percent and establish separate sector-level benchmarks to reduce carbon tax costs for Renewable Fuel Standards industrial facilities. In 2018, the federal government finalized 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 and British Columbia have developed 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 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. The extent and magnitude of any adverse impacts of current or additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time, in part 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. There is also risk that we could face claims initiated by third parties relating to climate change or other environmental regulations. These claims could, among other things, result in litigation targeted against Cenovus and the oil and gas industry generally, and should any such litigation claims arise, they may have a material adverse effect on our business. Low Carbon Fuel Standards Existing and proposed environmental legislation and regulation 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. Environment and Climate Change Canada has published a regulatory framework on its proposed clean fuel standard regulation to be adopted under the Canadian Environmental Protection Act, 1999. 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 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 states of California and Oregon, and the province of British Columbia have implemented the Low Carbon Fuel Standard, the Clean Fuels Program, 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, importers, and fuel distributors in these jurisdictions are required to comply with the legislation. 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 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. The IMO’s goal is to significantly reduce the amount of sulphur oxide emanating from ships and it 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 ability of ship owners to install scrubbers, worldwide heavy sour crude production and additional heavy processing availability. 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 or activity in areas identified as critical habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal government in relation to their obligations under 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, a suite of initiatives have been undertaken to support caribou recovery, including: a) the Alberta Caribou Action and Range Planning Project to develop long term habitat management plans such that ranges may return to self-sustaining status, b) development of methods for long term Regional Access Management Plans c) mineral development deferral agreements, and, d) negotiation of conservation agreements under Section 11 of the Species at Risk Act, which seek to codify concrete measures to support the conservation of the species and the protection of its critical habitat. If plans and actions undertaken 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. For example, the federal government is undertaking an imminent threat assessment for a portion of caribou herd range in West Central Alberta which may compel further intervention (this range does not overlap Cenovus’s lands or operations), a habitat protection order under Section 58 of the Species at Risk Act is pending for federally administered lands (including the Saskatchewan side of the Cold Lake Air Weapons Range to the east of Cenovus operations), and is the subject of an application for a protection order for the critical habitat of five sub- populations of woodland caribou. On January 24, 2019, the Athabasca Chipewyan and Mikisew Cree First Nations in northern Alberta, together with the Alberta Wilderness Association and the David Suzuki Foundation, filed an application for judicial review in federal court arguing that the Minister has failed to protect the habitat of five boreal woodland caribou herds. The applicants claim that although the Minister acknowledges that provincial recovery plans for the threatened species are inadequate, the federal government has not fulfilled its duty to issue a protective order under the Species at Risk Act. 2018 ANNUAL REPORT | 51 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 nitrogen dioxide, sulphur dioxide, fine particulate matter (“PM2.5”) and ozone were introduced as part of a national Air Quality Management System. 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 legislation expands the assessment considerations beyond the environment to include health, 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 regulatory proposals are subject to change as they work through the Parliamentary process. The extent and magnitude of any adverse impacts resulting from these proposed legislative changes on project development and operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to their implementation and what the accompanying regulations, including the types of projects that will be assessed under the new legislation. 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 2018, the Government of British Columbia continued progressing their commitments 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 Environmental Assessment Act was passed in the Fall of 2018 and allows wide discretionary powers to the Minister to designate a project for review on request from the public. The government has also implemented its commitment to proceed with a scientific review of hydraulic fracturing to determine impacts on water and the relationship to seismic activity for which the report will be released in 2019. In January 2018, the Government of British Columbia proposed restrictions on the increase of diluted bitumen transportation as part of the second phase of regulations to improve preparedness, response and recovery from potential oil spills. In March of 2018, the Government of British Columbia submitted a court reference to the British Columbia Court of Appeal to confirm whether or not it is within their jurisdiction to regulate transportation of bitumen within the province, as set out in the proposed regulation. The court reference has not yet been heard. 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. 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 52 | CENOVUS ENERGY 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, as projects approved prior to July 4, 2016 are exempted from the policy. However, new project developments and future phase expansions that have not yet been approved are expected to be subject to this policy. As our oil sands leases are in areas where wetlands cover over 50 percent of the landscape, avoidance of wetlands is not possible. In addition, Deep Basin development activities are subject to the policy if they occur in wetlands. In these cases we are required to comply with requirements for wetland reclamation or, where permanent wetland loss will occur, payment to an in-lieu fee program, or permittee-responsible replacement action. Based on the Alberta Wetland Mitigation Directive, 2018 and consultation with Alberta Environment and Parks as well as the AER, we do not anticipate a material impact of the policy on our oil sands or unconventional assets in the Deep Basin. 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. Reputation Risk continue operations. 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 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 nitrogen dioxide, sulphur dioxide, fine particulate matter (“PM2.5”) and ozone were introduced as part of a national Air Quality Management System. 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 legislation expands the assessment considerations beyond the environment to include health, 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 regulatory proposals are subject to change as they work through the Parliamentary process. The extent and magnitude of any adverse impacts resulting from these proposed legislative changes on project development and operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to their implementation and what the accompanying regulations, including the types of projects that will be assessed under the new legislation. 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 2018, the Government of British Columbia continued progressing their commitments 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 Environmental Assessment Act was passed in the Fall of 2018 and allows wide discretionary powers to the Minister to designate a project for review on request from the public. The government has also implemented its commitment to proceed with a scientific review of hydraulic fracturing to determine impacts on water and the relationship to seismic activity for which the report will be released in 2019. In January 2018, the Government of British Columbia proposed restrictions on the increase of diluted bitumen transportation as part of the second phase of regulations to improve preparedness, response and recovery from potential oil spills. In March of 2018, the Government of British Columbia submitted a court reference to the British Columbia Court of Appeal to confirm whether or not it is within their jurisdiction to regulate transportation of bitumen within the province, as set out in the proposed regulation. The court reference has not yet been heard. 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. 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, as projects approved prior to July 4, 2016 are exempted from the policy. However, new project developments and future phase expansions that have not yet been approved are expected to be subject to this policy. As our oil sands leases are in areas where wetlands cover over 50 percent of the landscape, avoidance of wetlands is not possible. In addition, Deep Basin development activities are subject to the policy if they occur in wetlands. In these cases we are required to comply with requirements for wetland reclamation or, where permanent wetland loss will occur, payment to an in-lieu fee program, or permittee-responsible replacement action. Based on the Alberta Wetland Mitigation Directive, 2018 and consultation with Alberta Environment and Parks as well as the AER, we do not anticipate a material impact of the policy on our oil sands or unconventional assets in the Deep Basin. 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. 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. 2018 ANNUAL REPORT | 53 Public Perception of Alberta Oil Sands United States Tax Risk 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, water and land use practices and indigenous engagement 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. 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 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 Joint Arrangements 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 Toronto and New York stock exchanges, 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. 54 | CENOVUS ENERGY In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The 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 post-2017 net operating losses to 80 percent of taxable income; revises the previous 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 significant gaps in the legislation that will be filled through Treasury regulations. While Treasury has released a number of proposed regulations as of December 31, 2018, there is a possibility that public input during the regulatory comment period may cause Treasury to change its interpretation of certain provisions when the regulations are finalized. Negative consequences may arise as a result of continued developments associated with this legislation and accompanying regulations. 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. 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. • • life. 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 our 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 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. Public Perception of Alberta Oil Sands United States Tax Risk In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The 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 post-2017 net operating losses to 80 percent of taxable income; revises the previous 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 significant gaps in the legislation that will be filled through Treasury regulations. While Treasury has released a number of proposed regulations as of December 31, 2018, there is a possibility that public input during the regulatory comment period may cause Treasury to change its interpretation of certain provisions when the regulations are finalized. Negative consequences may arise as a result of continued developments associated with this legislation and accompanying regulations. 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. 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, water and land use practices and indigenous engagement 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. 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 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 Toronto and New York stock exchanges, 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. 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. In determining the classification of our joint arrangements under IFRS 11, we considered the following: • • 2018 ANNUAL REPORT | 55 • • • 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 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 the Company’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 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. 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. Changes to these assumptions and key sources of estimation 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- prices, by-rail 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. assumptions throughput, commodity terminal forward such use as As at December 31, 2018, 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, 2018 by our IQREs. 56 | CENOVUS ENERGY Crude Oil, NGLs and Natural Gas Prices gas reserves were: The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural Average Annual Increase Thereafter (percent) WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) (1) Assumes gas heating value of one MMBtu per thousand cubic feet. Discount and Inflation Rates 2019 2020 2021 2022 2023 58.58 51.55 70.10 1.88 64.60 59.58 79.21 2.31 68.20 65.89 83.33 2.74 71.00 68.61 86.20 3.05 72.81 70.53 88.16 3.21 2.0 2.1 2.0 2.0 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 settle the obligation and may change in response to numerous market factors. Refer to Note 25 of the Consolidated Financial Statements for more details on changes to decommissioning costs. Onerous Contract Provisions A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed the economic benefits expected to be derived from the contract. Determining when to record a provision for an onerous contract requires Management judgment and the use of estimates and assumptions, including the nature, extent and timing of future cash flows and discount rates related to the contract. 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 to measurement uncertainty. 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 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. Changes in Accounting Policies Effective January 1, 2018, Cenovus adopted IFRS 9, “Financial Instruments” (“IFRS 9”) replacing IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). The adoption of IFRS 9 did not have a material impact on our Consolidated Financial Statements. Effective January 1, 2018, Cenovus adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. The adoption of IFRS 15 did not have a material impact on our Consolidated Financial Statements. • • • 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 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 the Company’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 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. 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. Changes to these assumptions and key sources of estimation 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, 2018, 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, 2018 by our IQREs. Crude Oil, NGLs and Natural Gas Prices The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: 2019 2020 2021 2022 2023 WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) 58.58 51.55 70.10 1.88 64.60 59.58 79.21 2.31 68.20 65.89 83.33 2.74 71.00 68.61 86.20 3.05 (1) Assumes gas heating value of one MMBtu per thousand cubic feet. Discount and Inflation Rates Average Annual Increase Thereafter (percent) 2.0 2.1 2.0 2.0 72.81 70.53 88.16 3.21 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 settle the obligation and may change in response to numerous market factors. Refer to Note 25 of the Consolidated Financial Statements for more details on changes to decommissioning costs. Onerous Contract Provisions A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed the economic benefits expected to be derived from the contract. Determining when to record a provision for an onerous contract requires Management judgment and the use of estimates and assumptions, including the nature, extent and timing of future cash flows and discount rates related to the contract. 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. Changes in Accounting Policies Effective January 1, 2018, Cenovus adopted IFRS 9, “Financial Instruments” (“IFRS 9”) replacing IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). The adoption of IFRS 9 did not have a material impact on our Consolidated Financial Statements. Effective January 1, 2018, Cenovus adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. The adoption of IFRS 15 did not have a material impact on our Consolidated Financial Statements. 2018 ANNUAL REPORT | 57 Further information about changes to our accounting policies resulting from the adoption of IFRS 9 and IFRS 15 can be found in Note 4 to the Consolidated Financial Statements. CONTROL ENVIRONMENT 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, 2019 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates. 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 above recognition 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 and may be applied retrospectively or using a modified retrospective approach. We have selected to use the modified retrospective approach which does not require restatement of prior period financial information as the cumulative effect of applying the standard to prior periods is recorded as an adjustment to opening retained earnings. On initial adoption, we have elected to use the following practical expedients permitted under the standard: • • • Apply a single discount rate to a portfolio of leases with similar characteristics; Account for leases with a remaining term of less than 12 months as at January 1, 2019 as short-term leases; Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the underlying asset is of low dollar value; The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the lease; and Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”), for onerous contracts instead of reassessing the ROU asset for impairment on January 1, 2019. • • On adoption of IFRS 16, we will recognize lease liabilities in relation to leases under the principles of the new standard measured at the present value of the remaining lease payments, discounted using the interest rate implicit in the lease or our incremental borrowing rate as at January 1, 2019. The associated ROU assets will be measured at the amount equal to the lease liability on January 1, 2019 less any amount previously recognized under IAS 37 for onerous contracts with no impact on retained earnings. Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of approximately $1.5 billion and $0.9 billion, respectively. We have identified ROU assets and lease liabilities primarily related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the consolidated statement of earnings will be as follows: • Lower general and administrative expenses, transportation and blending costs, operating costs, purchased product and property, plant and equipment expenditures; Higher finance expenses due to the interest recognized on the lease obligations; and Higher depreciation expense related to the ROU assets. • • We have reviewed office space contracts where the Company is the lessor and as a result of these assessments will recognize a $16 million net investment from these leases on January 1, 2019. 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 will not have a significant impact on the Consolidated Financial Statements. 58 | CENOVUS ENERGY 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, 2018. 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, 2018. The Company previously limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin Assets, acquired by the Company through a business combination on May 17, 2017. During the second quarter of 2018, the Company completed the evaluation and integration of the controls, policies and procedures of the Deep Basin Assets. No material weaknesses or significant deficiencies were noted during the integration. There have been no changes during the year ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect ICFR. The effectiveness of our ICFR was audited as at December 31, 2018 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, 2018. 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 2017 CR report in August 2018 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 In 2019 we expect to see continued commodity price volatility and market access constraints for heavy oil exiting Alberta. On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production cut for Alberta producers to address the record-high light-heavy crude oil differentials impacting our industry. We had already begun voluntarily reducing production levels at our Foster Creek and Christina Lake facilities during the third and fourth quarters of 2018 in response to limited takeaway capacity and discounted heavy oil pricing, and continue to work with the AER to determine the impact that the mandatory production curtailment will have on Cenovus. While our production levels will be impacted due to the curtailment, the expected improvement to the oil price is anticipated to have a positive impact on our cash flows. We continue to look for ways to increase our margins through operating performance and cost leadership, while focusing on 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. In 2018, we strengthened our long-term market access position by signing rail agreements to transport approximately 100,000 barrels per day of heavy crude oil to various destinations on the U.S. Gulf Coast, providing a means to move our volumes out of Alberta and to a customer base in other market centres, as well as mitigating some of the price impact of pipeline congestion on those barrels. We also recently increased our committed capacity on the proposed Keystone XL Pipeline by 100,000 barrels per day. We expect that transportation challenges faced by our industry will continue to negatively impact heavy oil prices, demonstrating the need for increased utilization of rail within the industry, and for approved pipeline projects in North America to proceed as soon as possible. Through a continued focus on capital discipline and cost reductions, we have reduced the amount of capital needed to sustain our base business and expand our projects, which we believe will further help support our financial resilience. Further information about changes to our accounting policies resulting from the adoption of IFRS 9 and IFRS 15 can be found in Note 4 to the Consolidated Financial Statements. CONTROL ENVIRONMENT 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, 2019 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates. 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 above recognition 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 and may be applied retrospectively or using a modified retrospective approach. We have selected to use the modified retrospective approach which does not require restatement of prior period financial information as the cumulative effect of applying the standard to prior periods is recorded as an adjustment to opening retained earnings. On initial adoption, we have elected to use the following practical expedients permitted under the standard: Apply a single discount rate to a portfolio of leases with similar characteristics; Account for leases with a remaining term of less than 12 months as at January 1, 2019 as short-term leases; Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the underlying asset The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the is of low dollar value; lease; and Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”), for onerous contracts instead of reassessing the ROU asset for impairment on January 1, 2019. On adoption of IFRS 16, we will recognize lease liabilities in relation to leases under the principles of the new standard measured at the present value of the remaining lease payments, discounted using the interest rate implicit in the lease or our incremental borrowing rate as at January 1, 2019. The associated ROU assets will be measured at the amount equal to the lease liability on January 1, 2019 less any amount previously recognized under IAS 37 for onerous contracts with no impact on retained earnings. Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of approximately $1.5 billion and $0.9 billion, respectively. We have identified ROU assets and lease liabilities primarily related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the consolidated statement of earnings will be as follows: Lower general and administrative expenses, transportation and blending costs, operating costs, purchased product and property, plant and equipment expenditures; Higher finance expenses due to the interest recognized on the lease obligations; and Higher depreciation expense related to the ROU assets. We have reviewed office space contracts where the Company is the lessor and as a result of these assessments will recognize a $16 million net investment from these leases on January 1, 2019. 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 will not have a significant impact on the Consolidated Financial Statements. 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, 2018. 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, 2018. The Company previously limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin Assets, acquired by the Company through a business combination on May 17, 2017. During the second quarter of 2018, the Company completed the evaluation and integration of the controls, policies and procedures of the Deep Basin Assets. No material weaknesses or significant deficiencies were noted during the integration. There have been no changes during the year ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect ICFR. The effectiveness of our ICFR was audited as at December 31, 2018 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, 2018. 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 2017 CR report in August 2018 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 In 2019 we expect to see continued commodity price volatility and market access constraints for heavy oil exiting Alberta. On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production cut for Alberta producers to address the record-high light-heavy crude oil differentials impacting our industry. We had already begun voluntarily reducing production levels at our Foster Creek and Christina Lake facilities during the third and fourth quarters of 2018 in response to limited takeaway capacity and discounted heavy oil pricing, and continue to work with the AER to determine the impact that the mandatory production curtailment will have on Cenovus. While our production levels will be impacted due to the curtailment, the expected improvement to the oil price is anticipated to have a positive impact on our cash flows. We continue to look for ways to increase our margins through operating performance and cost leadership, while focusing on 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. In 2018, we strengthened our long-term market access position by signing rail agreements to transport approximately 100,000 barrels per day of heavy crude oil to various destinations on the U.S. Gulf Coast, providing a means to move our volumes out of Alberta and to a customer base in other market centres, as well as mitigating some of the price impact of pipeline congestion on those barrels. We also recently increased our committed capacity on the proposed Keystone XL Pipeline by 100,000 barrels per day. We expect that transportation challenges faced by our industry will continue to negatively impact heavy oil prices, demonstrating the need for increased utilization of rail within the industry, and for approved pipeline projects in North America to proceed as soon as possible. Through a continued focus on capital discipline and cost reductions, we have reduced the amount of capital needed to sustain our base business and expand our projects, which we believe will further help support our financial resilience. 2018 ANNUAL REPORT | 59 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 light crude oil prices to remain constructive and largely tied to the extent to which OPEC curtails production, as agreed to at their December 2018 meeting, the degree to which the U.S. enforces export sanctions on Iranian crude oil, and the degree to which global demand growth continues; Overall, crude oil price volatility is expected to decrease as inventories return to historical levels; • • We anticipate the Brent-WTI and the WTI-WTS differentials will narrow once additional pipeline capacity out of • the Permian basin becomes available in the second half of 2019; Continuous OPEC cuts, enforcement of Iranian sanctions, and Venezuelan production declines will be supportive of the recent narrowing of global light-heavy crude oil price differentials; • We expect that the WTI-WCS differential will remain largely tied to the extent to which mandatory temporary production curtailments in Alberta, the potential start-up of Enbridge Inc.’s Line 3 Replacement Project, and increasing crude-by-rail activity will reduce storage levels and support a narrower differential relative to recent highs; • We anticipate that the pending International Maritime Organization (IMO) regulations will cause light-heavy crude oil price differentials to widen, although the magnitude of the widening remains uncertain; and • We expect refining crack spreads will likely continue to fluctuate, adjusting for seasonal trends, and will narrow once the Brent-WTI differential narrows. Crude Oil Benchmarks Natural Gas Benchmarks ) 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 ( 60 55 50 45 40 35 30 25 ) d e t a c i d n i s a ( 3.50 3.00 2.50 2.00 1.50 1.00 0.50 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Forward Prices at December 31, 2018 Forward Prices at December 31, 2018 Brent C5 @ Edmonton WTI WCS WCS (C$/bbl) AECO (C$/MCf) NYMEX (US$/Mcf) Natural gas prices are anticipated to remain challenged with North American supply continuing to grow as a result of U.S. shale gas drilling and associated natural gas from oil plays. The AECO basis differential is expected to remain wide as increasing supply is anticipated to exceed the limits of existing pipeline capacity. We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each other, and emerging macro-economic factors. The Bank of Canada raised its benchmark lending rate twice in 2017 and three times again in 2018, marking a notable shift for Canada towards a tighter monetary policy. Refining 3-2-1 Crack Spread Benchmark Foreign Exchange ) l b b / $ S U e g a r e v a ( 25 20 15 10 5 0.76 0.75 0.74 0.73 0.72 0.71 ) 1 $ C / $ S U e g a r e v a ( Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Forward Prices at December 31, 2018 Forward Prices at December 31, 2018 Chicago US$/C$1 60 | CENOVUS ENERGY Our exposure to the light-heavy crude oil 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 light-heavy crude oil 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; Transportation commitments and arrangements – supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets, as well as utilizing our crude-by-rail terminal and entering into agreements with third parties to move additional rail volumes to alleviate a portion of near-term takeaway capacity constraints; Marketing agreements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production well rates in response to pipeline capacity constraints, crude-by-rail export capacity and crude oil price differentials; • • • • • and Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS differential. Natural gas and NGLs production associated with our Deep Basin Assets provide improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations. Key Priorities For 2019 Deleveraging and Disciplined Capital Investment In 2019, our focus will be on further deleveraging our balance sheet and maintaining capital discipline in an effort to position Cenovus to have the flexibility to balance increasing returns to shareholders with disciplined investment in high-return growth projects. Maintaining our financial resilience and flexibility while continuing to deliver safe and reliable operations remains a top priority. In 2019, we anticipate capital investment to be between $1.2 billion and $1.4 billion. We plan to direct the majority of our 2019 capital budget towards sustaining oil sands production, while supporting the completion of the Christina Lake phase G expansion, which is ahead of schedule and expected to be completed in the second quarter of 2019. We have flexibility on when we start production from Christina Lake phase G, and will take into consideration whether mandated production curtailments have been lifted and there is sustained improvement in market access and heavy oil benchmark prices. In response to the current commodity price environment and our continued focus on near- term debt reduction, we are taking a very disciplined approach in the Deep Basin, with the goal of reducing costs, improving efficiencies and maximizing value. With integration remaining an important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability work at the Refineries. As at December 31, 2018, our net debt position was $8.4 billion. Through a combination of cash on hand and available capacity on our committed credit facility, we have approximately $5.3 billion of liquidity as at December 31, 2018. Over the long-term, we continue to target a Net Debt to Adjusted EBIDTA ratio of less than 2.0 times. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure sufficient liquidity through all stages of the economic cycle. We remain committed to increasing shareholder value through cost leadership, capital discipline and safe and reliable operations. These commitments, in combination with our high-quality upstream assets and joint ownership in strong refining assets, are expected to strengthen our ability to generate free funds flow and continue to deleverage our balance sheet in 2019. 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. In 2018, we made significant progress in strengthening our long-term market access position through three-year strategic agreements with major rail companies to transport approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the U.S. Gulf Coast. We have already begun shipping under these contracts, and anticipate ramping up to 100,000 barrels per day through 2019. While we remain confident that new pipeline capacity will be constructed, these rail agreements will help get our oil to higher-price markets. 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. In addition to our rail agreements, we recently increased our committed capacity on the proposed Keystone XL Pipeline. Between Keystone XL and the Trans Mountain Expansion Project, we now have 275,000 barrels per day of potential future pipeline capacity to the West Coast and U.S. Gulf Coast. • • • • Our exposure to the light-heavy crude oil 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 light-heavy crude oil 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; Transportation commitments and arrangements – supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets, as well as utilizing our crude-by-rail terminal and entering into agreements with third parties to move additional rail volumes to alleviate a portion of near-term takeaway capacity constraints; Marketing agreements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production well rates in response to pipeline capacity constraints, crude-by-rail export capacity and crude oil price differentials; and Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS differential. 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 light crude oil prices to remain constructive and largely tied to the extent to which OPEC curtails production, as agreed to at their December 2018 meeting, the degree to which the U.S. enforces export sanctions on Iranian crude oil, and the degree to which global demand growth continues; Overall, crude oil price volatility is expected to decrease as inventories return to historical levels; • We anticipate the Brent-WTI and the WTI-WTS differentials will narrow once additional pipeline capacity out of the Permian basin becomes available in the second half of 2019; Continuous OPEC cuts, enforcement of Iranian sanctions, and Venezuelan production declines will be supportive of the recent narrowing of global light-heavy crude oil price differentials; • We expect that the WTI-WCS differential will remain largely tied to the extent to which mandatory temporary production curtailments in Alberta, the potential start-up of Enbridge Inc.’s Line 3 Replacement Project, and increasing crude-by-rail activity will reduce storage levels and support a narrower differential relative to recent • We anticipate that the pending International Maritime Organization (IMO) regulations will cause light-heavy crude oil price differentials to widen, although the magnitude of the widening remains uncertain; and • We expect refining crack spreads will likely continue to fluctuate, adjusting for seasonal trends, and will narrow once the Brent-WTI differential narrows. ) d e t a c i d n i s a ( 3.50 3.00 2.50 2.00 1.50 1.00 0.50 0.76 0.75 0.74 0.73 0.72 0.71 ) 1 $ C / $ S U e g a r e v a ( Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Forward Prices at December 31, 2018 Forward Prices at December 31, 2018 Brent C5 @ Edmonton WTI WCS WCS (C$/bbl) AECO (C$/MCf) NYMEX (US$/Mcf) Natural gas prices are anticipated to remain challenged with North American supply continuing to grow as a result of U.S. shale gas drilling and associated natural gas from oil plays. The AECO basis differential is expected to remain wide as increasing supply is anticipated to exceed the limits of existing pipeline capacity. We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each other, and emerging macro-economic factors. The Bank of Canada raised its benchmark lending rate twice in 2017 and three times again in 2018, marking a notable shift for Canada towards a tighter monetary policy. Refining 3-2-1 Crack Spread Benchmark Foreign Exchange Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Forward Prices at December 31, 2018 Forward Prices at December 31, 2018 Chicago US$/C$1 highs; ) 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 ( 60 55 50 45 40 35 30 25 ) l b b / $ S U e g a r e v a ( 25 20 15 10 5 Crude Oil Benchmarks Natural Gas Benchmarks Key Priorities For 2019 Natural gas and NGLs production associated with our Deep Basin Assets provide improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations. Deleveraging and Disciplined Capital Investment In 2019, our focus will be on further deleveraging our balance sheet and maintaining capital discipline in an effort to position Cenovus to have the flexibility to balance increasing returns to shareholders with disciplined investment in high-return growth projects. Maintaining our financial resilience and flexibility while continuing to deliver safe and reliable operations remains a top priority. In 2019, we anticipate capital investment to be between $1.2 billion and $1.4 billion. We plan to direct the majority of our 2019 capital budget towards sustaining oil sands production, while supporting the completion of the Christina Lake phase G expansion, which is ahead of schedule and expected to be completed in the second quarter of 2019. We have flexibility on when we start production from Christina Lake phase G, and will take into consideration whether mandated production curtailments have been lifted and there is sustained improvement in market access and heavy oil benchmark prices. In response to the current commodity price environment and our continued focus on near- term debt reduction, we are taking a very disciplined approach in the Deep Basin, with the goal of reducing costs, improving efficiencies and maximizing value. With integration remaining an important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability work at the Refineries. As at December 31, 2018, our net debt position was $8.4 billion. Through a combination of cash on hand and available capacity on our committed credit facility, we have approximately $5.3 billion of liquidity as at December 31, 2018. Over the long-term, we continue to target a Net Debt to Adjusted EBIDTA ratio of less than 2.0 times. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure sufficient liquidity through all stages of the economic cycle. We remain committed to increasing shareholder value through cost leadership, capital discipline and safe and reliable operations. These commitments, in combination with our high-quality upstream assets and joint ownership in strong refining assets, are expected to strengthen our ability to generate free funds flow and continue to deleverage our balance sheet in 2019. 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. In 2018, we made significant progress in strengthening our long-term market access position through three-year strategic agreements with major rail companies to transport approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the U.S. Gulf Coast. We have already begun shipping under these contracts, and anticipate ramping up to 100,000 barrels per day through 2019. While we remain confident that new pipeline capacity will be constructed, these rail agreements will help get our oil to higher-price markets. 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. In addition to our rail agreements, we recently increased our committed capacity on the proposed Keystone XL Pipeline. Between Keystone XL and the Trans Mountain Expansion Project, we now have 275,000 barrels per day of potential future pipeline capacity to the West Coast and U.S. Gulf Coast. 2018 ANNUAL REPORT | 61 Cost Leadership Over the past four years, we have achieved significant improvements in our operating and sustaining capital costs. We will continue to look for ways to improve efficiencies across Cenovus to drive incremental capital, operating and general and administrative cost reductions. We expect to realize additional savings through 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, financial resilience and our ability to generate shareholder value. We believe growth in cash flows and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than 2.0 times. Advance Focused Technology and Innovation to Achieve Margin Improvement We have always believed that technology and innovation are differentiating factors in our industry. 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 in an effort to leverage our technology spend. 62 | CENOVUS ENERGY Cost Leadership Over the past four years, we have achieved significant improvements in our operating and sustaining capital costs. We will continue to look for ways to improve efficiencies across Cenovus to drive incremental capital, operating and general and administrative cost reductions. We expect to realize additional savings through 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, financial resilience and our ability to generate shareholder value. We believe growth in cash flows and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than 2.0 times. Advance Focused Technology and Innovation to Achieve Margin Improvement We have always believed that technology and innovation are differentiating factors in our industry. 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 in an effort to leverage our technology spend. CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2018 TABLE OF CONTENTS 64 65 67 REPORT OF MANAGEMENT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) 68 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 69 70 71 72 CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY CONSOLIDATED STATEMENTS OF CASH FLOWS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 72 75 75 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 98 19. OTHER ASSETS 98 20. GOODWILL 98 21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 98 22. LONG-TERM DEBT AND CAPITAL STRUCTURE 84 4. CHANGES IN ACCOUNTING POLICIES 85 5. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY 101 23. CONTINGENT PAYMENT 101 24. ONEROUS CONTRACT PROVISIONS 102 25. DECOMMISSIONING LIABILITIES 87 6. FINANCE COSTS 102 26. OTHER LIABILITIES 87 7. FOREIGN EXCHANGE (GAIN) LOSS, NET 87 8. DIVESTITURES 87 9. ACQUISITION 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 96 15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES 96 16. INVENTORIES 102 27. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS 105 28. SHARE CAPITAL 106 29. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) 106 30. STOCK-BASED COMPENSATION PLANS 109 31. EMPLOYEE SALARIES AND BENEFIT EXPENSES 109 32. RELATED PARTY TRANSACTIONS 109 33. FINANCIAL INSTRUMENTS 111 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 116 37. SUBSEQUENT EVENT 2018 ANNUAL REPORT | 63 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 five 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, 2018. 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, 2018. 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, 2018, as stated in their Report of Independent Registered Public Accounting Firm dated February 12, 2019. PricewaterhouseCoopers LLP has provided such opinions. /s/ Alexander J. Pourbaix Alexander J. Pourbaix President & Chief Executive Officer Cenovus Energy Inc. February 12, 2019 /s/ Jonathan M. McKenzie Jonathan M. McKenzie Executive Vice-President & Chief Financial Officer Cenovus Energy Inc. 64 | CENOVUS ENERGY REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM REPORT OF INDEPENDENT REGISTERED PUBLIC To the Shareholders and Board of Directors of Cenovus Energy Inc. Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting ACCOUNTING FIRM We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries, To the Shareholders and Board of Directors of Cenovus Energy Inc. (together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries, financial statements”). We also have audited the Company's internal control over financial reporting as of (together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). in the period ended December 31, 2018, 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 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). cash flows for each of the three years in the period ended December 31, 2018 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also in our In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the cash flows for each of the three years in the period ended December 31, 2018 in conformity with International COSO. 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, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Basis for Opinions COSO. 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 Basis for Opinions 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 The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting based on our audits. We are a public accounting firm registered with the internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with reporting, included in the accompanying Management's Assessment of Internal Control over Financial Reporting. respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's of the Securities and Exchange Commission and the PCAOB. 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 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of of the Securities and Exchange Commission and the PCAOB. material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. 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 Our audits of the consolidated financial statements included performing procedures to assess the risks of material material misstatement, whether due to error or fraud, and whether effective internal control over financial misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures reporting was maintained in all material respects. 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 Our audits of the consolidated financial statements included performing procedures to assess the risks of material principles used and significant estimates made by management, as well as evaluating the overall presentation of misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our principles used and significant estimates made by management, as well as evaluating the overall presentation of audits also included performing such other procedures as we considered necessary in the circumstances. We the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an believe that our audits provide a reasonable basis for our opinions. 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. PricewaterhouseCoopers LLP T: +1 403 509 7500, F: +1 403 781 1825 PricewaterhouseCoopers LLP T: +1 403 509 7500, F: +1 403 781 1825 Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3 “PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership. Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3 “PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership. 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 five 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, 2018. 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, 2018. 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, 2018, as stated in their Report of Independent Registered Public Accounting Firm dated February 12, 2019. PricewaterhouseCoopers LLP has provided such opinions. /s/ Alexander J. Pourbaix Alexander J. Pourbaix President & Chief Executive Officer Cenovus Energy Inc. February 12, 2019 /s/ Jonathan M. McKenzie Jonathan M. McKenzie Executive Vice-President & Chief Financial Officer Cenovus Energy Inc. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM REPORT OF INDEPENDENT REGISTERED PUBLIC To the Shareholders and Board of Directors of Cenovus Energy Inc. ACCOUNTING FIRM 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, To the Shareholders and Board of Directors of Cenovus Energy Inc. (together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries, financial statements”). We also have audited the Company's internal control over financial reporting as of (together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). in the period ended December 31, 2018, 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 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). cash flows for each of the three years in the period ended December 31, 2018 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also in our In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the cash flows for each of the three years in the period ended December 31, 2018 in conformity with International COSO. 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 Basis for Opinions December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO. 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 Basis for Opinions 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 The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting based on our audits. We are a public accounting firm registered with the internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with reporting, included in the accompanying Management's Assessment of Internal Control over Financial Reporting. respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's of the Securities and Exchange Commission and the PCAOB. 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 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of of the Securities and Exchange Commission and the PCAOB. material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. 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 Our audits of the consolidated financial statements included performing procedures to assess the risks of material material misstatement, whether due to error or fraud, and whether effective internal control over financial misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures reporting was maintained in all material respects. 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 Our audits of the consolidated financial statements included performing procedures to assess the risks of material principles used and significant estimates made by management, as well as evaluating the overall presentation of misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our principles used and significant estimates made by management, as well as evaluating the overall presentation of audits also included performing such other procedures as we considered necessary in the circumstances. We the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an believe that our audits provide a reasonable basis for our opinions. 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. PricewaterhouseCoopers LLP Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3 T: +1 403 509 7500, F: +1 403 781 1825 PricewaterhouseCoopers LLP “PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership. Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3 T: +1 403 509 7500, F: +1 403 781 1825 “PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership. 2018 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 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 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 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 Chartered Professional Accountants Calgary, Alberta, Canada February 12, 2019 We have served as the Company’s auditor since 2008. 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 Onerous Contract Provisions 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 See accompanying Notes to Consolidated Financial Statements. Notes 2018 2017 2016 21,389 17,314 11,015 545 271 9 20,844 17,043 11,006 33 10,18 10,17 1 1 24 6 7 9 9 23 8 12 11 13 8,744 5,942 2,184 1 305 2,131 2,123 391 629 627 (19 ) 854 - - 50 25 795 (12 ) (3,926 ) (1,010 ) (2,916 ) 247 (2,669 ) 8,033 3,748 1,949 1 896 1,838 888 300 8 645 (62 ) (812 ) (2,555 ) 56 (138 ) 36 1 (5 ) 2,216 (52 ) 2,268 1,098 3,366 (2.37 ) 0.20 (2.17 ) 2.06 0.99 3.05 6,978 1,715 1,239 - 401 931 2 318 8 390 (52 ) (198 ) - - - 36 6 34 (802 ) (343 ) (459 ) (86 ) (545 ) (0.55 ) (0.10 ) (0.65 ) 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 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 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 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 Chartered Professional Accountants Calgary, Alberta, Canada February 12, 2019 We have served as the Company’s auditor since 2008. 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 Onerous Contract Provisions 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 ($) Continuing Operations Discontinued Operations Net Earnings (Loss) Per Share See accompanying Notes to Consolidated Financial Statements. Notes 2018 2017 2016 1 1 33 10,18 10,17 24 6 7 9 9 23 8 12 11 13 21,389 545 20,844 17,314 271 17,043 11,015 9 11,006 8,744 5,942 2,184 1 305 2,131 2,123 391 629 627 (19 ) 854 - - 50 25 795 (12 ) (3,926 ) (1,010 ) (2,916 ) 247 (2,669 ) 8,033 3,748 1,949 1 896 1,838 888 300 8 645 (62 ) (812 ) (2,555 ) 56 (138 ) 36 1 (5 ) 2,216 (52 ) 2,268 1,098 3,366 (2.37 ) 0.20 (2.17 ) 2.06 0.99 3.05 6,978 1,715 1,239 - 401 931 2 318 8 390 (52 ) (198 ) - - - 36 6 34 (802 ) (343 ) (459 ) (86 ) (545 ) (0.55 ) (0.10 ) (0.65 ) 2018 ANNUAL REPORT | 67 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the years ended December 31, ($ 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 Changes in the Fair Value of Equity Instruments at FVOCI (1) Items That May be Reclassified to Profit or Loss: Foreign Currency Translation Adjustment Total Other Comprehensive Income (Loss), Net of Tax Comprehensive Income (Loss) (1) Fair Value through Other Comprehensive Income (“FVOCI”). See accompanying Notes to Consolidated Financial Statements. Notes 2018 2017 2016 (2,669 ) 3,366 (545 ) 29 (3 ) 1 397 395 (2,274 ) 9 (1 ) (275 ) (267 ) 3,099 (3 ) (1 ) (106 ) (110 ) (655 ) 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 Current Portion of Long-Term Debt Contingent Payment Onerous Contract Provisions Income Tax Payable Risk Management Liabilities Related to Assets Held for Sale Total Current Liabilities Long-Term Debt Contingent Payment Onerous Contract Provisions Risk Management Decommissioning Liabilities Other Liabilities Deferred Income Taxes Total Liabilities Shareholders’ Equity Notes 2018 2017 14 15 16 33,34 11 1,17 1,18 33,34 19 1,20 21 22 23 24 33,34 11 33,34 22 23 24 25 26 12 781 1,238 - 1,013 163 - 3,195 785 28,698 160 - 64 2,272 35,174 1,833 682 15 50 17 3 - 2,600 8,482 117 613 - 875 158 4,861 17,706 17,468 35,174 610 1,830 68 1,389 63 1,048 5,008 3,673 29,596 311 2 71 2,272 40,933 2,627 - 38 8 129 1,031 603 4,436 9,513 168 37 20 1,029 136 5,613 20,952 19,981 40,933 Total Liabilities and Shareholders’ Equity Commitments and Contingencies 36 See accompanying Notes to Consolidated Financial Statements. Approved by the Board of Directors /s/ Patrick D. Daniel Patrick D. Daniel Director Cenovus Energy Inc. /s/ Colin Taylor Colin Taylor Director Cenovus Energy Inc. 68 | CENOVUS ENERGY CONSOLIDATED STATEMENTS OF COMPREHENSIVE CONSOLIDATED BALANCE SHEETS INCOME (LOSS) For the years ended December 31, ($ millions) Items That Will Not be Reclassified to Profit or Loss: Actuarial Gain (Loss) Relating to Pension and Other Post- Retirement Benefits Changes in the Fair Value of Equity Instruments at FVOCI (1) Items That May be Reclassified to Profit or Loss: Foreign Currency Translation Adjustment Total Other Comprehensive Income (Loss), Net of Tax Comprehensive Income (Loss) (1) Fair Value through Other Comprehensive Income (“FVOCI”). See accompanying Notes to Consolidated Financial Statements. Net Earnings (Loss) (2,669 ) 3,366 (545 ) Other Comprehensive Income (Loss), Net of Tax 29 Notes 2018 2017 2016 (3 ) 1 397 395 (2,274 ) 9 (1 ) (275 ) (267 ) 3,099 (3 ) (1 ) (106 ) (110 ) (655 ) 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 Current Portion of Long-Term Debt Contingent Payment Onerous Contract Provisions Income Tax Payable Risk Management Liabilities Related to Assets Held for Sale Total Current Liabilities Long-Term Debt Contingent Payment Onerous Contract Provisions Risk Management Decommissioning Liabilities Other Liabilities Deferred Income Taxes Total Liabilities Shareholders’ Equity 14 15 16 33,34 11 1,17 1,18 33,34 19 1,20 21 22 23 24 33,34 11 22 23 24 33,34 25 26 12 Total Liabilities and Shareholders’ Equity Commitments and Contingencies 36 See accompanying Notes to Consolidated Financial Statements. Approved by the Board of Directors /s/ Patrick D. Daniel Patrick D. Daniel Director Cenovus Energy Inc. /s/ Colin Taylor Colin Taylor Director Cenovus Energy Inc. Notes 2018 2017 781 1,238 - 1,013 163 - 3,195 785 28,698 160 - 64 2,272 35,174 1,833 682 15 50 17 3 - 2,600 8,482 117 613 - 875 158 4,861 17,706 17,468 35,174 610 1,830 68 1,389 63 1,048 5,008 3,673 29,596 311 2 71 2,272 40,933 2,627 - 38 8 129 1,031 603 4,436 9,513 168 37 20 1,029 136 5,613 20,952 19,981 40,933 2018 ANNUAL REPORT | 69 CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY CONSOLIDATED STATEMENTS OF CASH FLOWS ($ millions) 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 Net Earnings (Loss) Other Comprehensive Income (Loss) Total Comprehensive Income (Loss) Stock-Based Compensation Expense Dividends on Common Shares As at December 31, 2018 Share Capital (Note 28) Paid in Surplus (Note 28) Retained Earnings AOCI (1) (Note 29) Total 5,534 - - - - - 5,534 - - - 5,506 - - 11,040 - - - - - 11,040 4,330 - - - 20 - 4,350 - - - - 11 - 4,361 - - - 6 - 4,367 1,507 (545 ) - (545 ) - (166 ) 796 3,366 - 3,366 - - (225 ) 3,937 (2,669 ) - (2,669 ) - (245 ) 1,023 1,020 - (110 ) (110 ) - - 910 - (267 ) (267 ) - - - 643 - 395 395 - - 1,038 12,391 (545 ) (110 ) (655 ) 20 (166 ) 11,590 3,366 (267 ) 3,099 5,506 11 (225 ) 19,981 (2,669 ) 395 (2,274 ) 6 (245 ) 17,468 (1) Accumulated Other Comprehensive Income (Loss). See accompanying Notes to Consolidated Financial Statements. For the years ended December 31, ($ millions) Operating Activities Net Earnings (Loss) Exploration Expense Deferred Income Taxes Depreciation, Depletion and Amortization 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 Unwinding of Discount on Decommissioning Liabilities Onerous Contract Provisions, Net of Cash Paid Other Asset Impairments Realized Foreign Exchange (Gain) Loss on Non-Operating Items Other Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Cash From (Used in) Operating Activities Investing Activities Acquisition, Net of Cash Acquired Capital Expenditures – Exploration and Evaluation Assets Capital Expenditures – Property, Plant and Equipment Proceeds From Divestitures Net Change in Investments and Other Net Change in Non-Cash Working Capital Cash From (Used in) Investing Activities Financing Activities Issuance of Long-Term Debt (Repayment) 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 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 See accompanying Notes to Consolidated Financial Statements. Notes 2018 2017 2016 18 17 12 33 7 9 23 11 8 25 24 10 9 17 18 8,11 35 22 22 22 22 22 28 13 (2,669 ) 2,131 2,123 (794 ) (1,249 ) 649 - 50 (301 ) 795 63 618 - 206 52 (72 ) 552 2,154 - (55 ) (1,322 ) 1,050 9 (295 ) (613 ) (1,144 ) (20 ) - - - (245 ) (1 ) (1,410 ) 40 171 610 781 3,366 2,030 890 583 729 (857 ) (2,555 ) (138 ) (1,285 ) 1 128 (8 ) - (18 ) 48 (107 ) 252 3,059 (14,565 ) (147 ) (1,523 ) 3,210 - 159 - 32 3,569 (3,600 ) 2,899 (225 ) (2 ) 6,515 182 (3,110 ) 3,720 610 (545 ) 1,498 2 (209 ) 554 (189 ) - - - 6 130 53 30 1 92 (91 ) (471 ) 861 - (67 ) (967 ) 8 (1 ) (52 ) - - - - - - (166 ) (2 ) (168 ) 1 (385 ) 4,105 3,720 (12,866 ) (1,079 ) - 3,842 Net Cash Provided (Used) Before Financing Activities 1,541 (9,807 ) (218 ) 70 | CENOVUS ENERGY CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY CONSOLIDATED STATEMENTS OF CASH FLOWS ($ millions) 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 Net Earnings (Loss) Other Comprehensive Income (Loss) Total Comprehensive Income (Loss) Stock-Based Compensation Expense Dividends on Common Shares As at December 31, 2018 Share Capital Paid in Surplus Retained Earnings (Note 28) (Note 28) AOCI (1) (Note 29) Total 5,534 4,330 5,534 4,350 11,040 4,361 - - - - - - - - - - - - - - - 5,506 - - - 20 - - - - - 11 - - - - 6 - 1,507 (545 ) - (545 ) - (166 ) 796 3,366 - 3,366 - - (225 ) 3,937 (2,669 ) (2,669 ) - - (245 ) 1,023 1,020 - (110 ) (110 ) - - 910 - (267 ) (267 ) - - - 643 - 395 395 - - 12,391 (545 ) (110 ) (655 ) 20 (166 ) 11,590 3,366 (267 ) 3,099 5,506 11 (225 ) 19,981 (2,669 ) 395 (2,274 ) 6 (245 ) 11,040 4,367 1,038 17,468 (1) Accumulated Other Comprehensive Income (Loss). See accompanying Notes to Consolidated Financial Statements. For the years ended December 31, ($ millions) 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 Unwinding of Discount on Decommissioning Liabilities Onerous Contract Provisions, Net of Cash Paid Other Asset Impairments Realized Foreign Exchange (Gain) Loss on Non-Operating Items Other Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Cash From (Used in) Operating Activities Investing Activities Acquisition, Net of Cash Acquired Capital Expenditures – Exploration and Evaluation Assets Capital Expenditures – Property, Plant and Equipment Proceeds From Divestitures Net Change in Investments and Other Net Change in Non-Cash Working Capital Cash From (Used in) Investing Activities Notes 2018 2017 2016 18 17 12 33 7 9 23 11 8 25 24 10 9 17 18 8,11 (2,669 ) 2,131 2,123 (794 ) (1,249 ) 649 - 50 (301 ) 795 63 618 - 206 52 (72 ) 552 2,154 - (55 ) (1,322 ) 1,050 9 (295 ) (613 ) 3,366 2,030 890 583 729 (857 ) (2,555 ) (138 ) (1,285 ) 1 128 (8 ) - (18 ) 48 (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 1 92 (91 ) (471 ) 861 - (67 ) (967 ) 8 (1 ) (52 ) (1,079 ) Net Cash Provided (Used) Before Financing Activities 1,541 (9,807 ) (218 ) Financing Activities Issuance of Long-Term Debt (Repayment) 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 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 See accompanying Notes to Consolidated Financial Statements. 35 22 22 22 22 22 28 13 - (1,144 ) (20 ) - - - (245 ) (1 ) (1,410 ) 40 171 610 781 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 2018 ANNUAL REPORT | 71 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES A) Results of Operations – Segment and Operational Information 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. 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 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 2.8 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. These 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 include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices. 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, the Company announced its intention to divest of its Conventional segment that included its heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of operations have been reported as a discontinued operation (see Note 11). As at January 5, 2018, all of the Company’s Conventional assets were sold. The following tabular financial information presents the segmented information first by segment, then by product and geographic location. For the years ended December 31, 2018 2017 2016 2018 2017 2016 2018 2017 2016 Oil Sands Deep Basin Refining and Marketing Revenues Gross Sales Less: Royalties Expenses Purchased Product 10,026 7,362 2,929 904 555 - 11,183 9,852 8,439 473 230 9 72 41 - - - - 9,553 7,132 2,920 832 514 - 11,183 9,852 8,439 - - - - 9,261 8,476 7,325 - 90 - 56 Transportation and Blending 5,879 3,704 1,721 Operating 1,037 934 501 403 250 Production and Mineral Taxes - - - (Gain) Loss on Risk Management 1,551 307 (179 ) 1 26 1 - 1,086 2,187 877 312 207 Operating Margin Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) (359 ) 69 220 (2,217 ) (124 ) 1,439 1,230 655 412 331 6 888 2 2,117 - - - - - - - - - - - - 927 772 742 - (1 ) - 6 - 26 996 598 346 222 215 211 - - - 774 383 135 For the years ended December 31, 2018 2017 2016 2018 2017 2016 Corporate and Eliminations Consolidated 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 Onerous Contract Provisions Foreign Exchange (Gain) Loss, Net Finance Costs Interest Income Revaluation (Gain) Transaction Costs Re-measurement of Contingent Payment Research Costs (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net (724 ) (455 ) (353 ) 21,389 17,314 11,015 - - - 545 271 9 (724 ) (455 ) (353 ) 20,844 17,043 11,006 (517 ) (443 ) (347 ) 8,744 8,033 6,978 (27 ) (12 ) (6 ) 5,942 3,748 1,715 (183 ) (4 ) 2,184 1,949 1,239 (7 ) - - 1 1 (1,271 ) 583 554 305 896 62 65 2,131 1,838 - - 2,123 888 - 58 - - 401 931 2 1,216 (638 ) (615 ) (586 ) (310 ) (260 ) 391 629 627 (19 ) 300 318 8 8 645 390 (62 ) (52 ) 854 (812 ) (198 ) - (2,555 ) - 56 50 (138 ) 25 795 (12 ) 36 1 (5 ) - - - 36 6 34 391 629 627 (19 ) 854 - 50 25 795 (12 ) 300 318 8 8 645 390 (62 ) (52 ) (812 ) (198 ) 56 (138 ) 36 1 (5 ) - - - 36 6 34 - (2,555 ) 3,340 (2,526 ) 542 3,340 (2,526 ) 542 Earnings (Loss) From Continuing Operations Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) From Continuing Operations (3,926 ) 2,216 (802 ) (1,010 ) (52 ) (343 ) (2,916 ) 2,268 (459 ) 72 | CENOVUS ENERGY 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. 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 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 2.8 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. These 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 include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices. 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, the Company announced its intention to divest of its Conventional segment that included its heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of operations have been reported as a discontinued operation (see Note 11). As at January 5, 2018, all of the Company’s Conventional assets were sold. The following tabular financial information presents the segmented information first by segment, then by product and geographic location. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES A) Results of Operations – Segment and Operational Information Oil Sands Deep Basin For the years ended December 31, Revenues Gross Sales Less: Royalties Expenses 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) 2018 2017 2016 2018 2017 2016 Refining and Marketing 2018 2017 2016 10,026 7,362 2,929 9 9,553 7,132 2,920 473 230 904 72 832 555 41 514 - 11,183 9,852 8,439 - - - 11,183 9,852 8,439 - - - - - 5,879 3,704 1,721 934 501 1,037 - - 1,551 307 (179 ) 1,086 2,187 877 - - 90 403 1 26 312 1,439 1,230 655 6 (359 ) 888 412 2 2,117 69 220 (2,217 ) - 56 250 1 - 207 331 - (124 ) - 9,261 8,476 7,325 - - - - - - - 927 - (1 ) 996 - 772 - 6 598 742 - 346 26 - - - 222 - 774 215 - 383 211 - 135 For the years ended December 31, 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 Onerous Contract Provisions 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 Corporate and Eliminations 2018 2017 2016 Consolidated 2018 2017 2016 (724 ) - (724 ) (517 ) (27 ) (183 ) - (1,271 ) 58 - 1,216 391 629 627 (19 ) 854 (455 ) (353 ) 21,389 17,314 11,015 9 (455 ) (353 ) 20,844 17,043 11,006 545 271 - - (443 ) (347 ) 8,744 8,033 6,978 (6 ) 5,942 3,748 1,715 (4 ) 2,184 1,949 1,239 - (12 ) (7 ) - 1 - 583 554 1 305 896 65 2,131 1,838 888 62 - 401 931 2 8 (638 ) (615 ) 300 318 8 645 390 (52 ) (62 ) (812 ) (198 ) - - - 36 6 34 - (2,555 ) 56 - (138 ) 50 36 25 1 795 (5 ) (12 ) - 2,123 (586 ) 391 629 627 (19 ) 854 (310 ) (260 ) 300 318 8 8 645 390 (62 ) (812 ) - (2,555 ) - 56 50 (138 ) 25 36 795 (12 ) (52 ) (198 ) - - - 36 6 34 542 1 (5 ) 3,340 (2,526 ) 542 3,340 (2,526 ) Earnings (Loss) From Continuing Operations Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) From Continuing Operations (3,926 ) 2,216 (1,010 ) (52 ) (2,916 ) 2,268 (802 ) (343 ) (459 ) 2018 ANNUAL REPORT | 73 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 B) Revenues by Product For the years ended December 31, 2018 2017 2016 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Upstream Crude Oil Natural Gas NGLs Other Refined Product Market Optimization Corporate and Eliminations Revenues From Continuing Operations C) Geographical Information For the years ended December 31, Canada United States Consolidated As at December 31, Canada (2) United States Consolidated 9,662 321 333 69 9,032 2,151 (724 ) 20,844 7,184 235 184 43 7,312 2,540 (455 ) 17,043 Revenues 2018 11,695 9,149 20,844 2017 9,723 7,320 17,043 2,902 16 - 2 5,972 2,467 (353 ) 11,006 2016 4,978 6,028 11,006 Non-Current Assets (1) 2018 27,644 4,175 31,819 2017 31,756 3,856 35,612 Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), other assets and goodwill. (1) (2) Certain crude oil and natural gas properties of the Deep Basin segment, which reside in Canada, were reclassified in 2018 to PP&E and E&E from have been prepared in compliance with IFRS. assets held for sale in current assets. 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 $2,500 million (2017 – $1,713 million; 2016 – $974 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, 2018, Cenovus had three customers (2017 – two; 2016 – 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 $7,840 million, $2,285 million and $2,263 million, respectively (2017 – $5,655 million and $1,964 million; 2016 – $4,742 million, $1,623 million and $1,400 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, Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Consolidated As at December 31, Oil Sands Deep Basin Conventional Refining and Marketing Corporate and Eliminations Consolidated 74 | CENOVUS ENERGY E&E Assets 2018 639 146 - - 785 Goodwill 2018 2,272 - - - - 2,272 2017 617 3,056 - - 3,673 2017 2,272 - - - - 2,272 PP&E 2018 21,646 2,482 4,284 286 28,698 2017 22,320 3,019 3,967 290 29,596 Total Assets 2018 25,373 2,742 14 5,621 1,424 35,174 2017 26,799 6,694 644 5,432 1,364 40,933 E) Capital Expenditures (1) For the years ended December 31, Capital Investment Oil Sands Deep Basin Conventional Refining and Marketing Corporate and Eliminations Acquisition Capital Oil Sands (2) Deep Basin Total Capital Expenditures 2018 2017 2016 887 211 - 208 57 973 225 206 180 77 604 - 171 220 31 1,363 1,661 1,026 332 9 1,704 11,614 6,774 20,049 11 - 1,037 Includes expenditures on PP&E, E&E assets and assets held for sale. (1) (2) In connection with the acquisition discussed in Note 9, Cenovus was deemed to have disposed of its pre-existing interest in FCCL Partnership (“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 $11,605 million as at May 17, 2017. 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ 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 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 12, 2019. 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 discussed in Note 9, 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 For the years ended December 31, 2018 2017 2016 Revenues From Continuing Operations 20,844 17,043 11,006 9,662 7,184 2,902 321 333 69 9,032 2,151 (724 ) 235 184 43 7,312 2,540 (455 ) 16 - 2 5,972 2,467 (353 ) Revenues 2018 11,695 9,149 20,844 2017 9,723 7,320 2016 4,978 6,028 17,043 11,006 Non-Current Assets (1) 2018 27,644 4,175 31,819 2017 31,756 3,856 35,612 (1) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), other assets and goodwill. (2) Certain crude oil and natural gas properties of the Deep Basin segment, which reside in Canada, were reclassified in 2018 to PP&E and E&E from Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers outside of Canada were $2,500 million (2017 – $1,713 million; 2016 – $974 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, 2018, Cenovus had three customers (2017 – two; 2016 – 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 $7,840 million, $2,285 million and $2,263 million, respectively (2017 – $5,655 million and $1,964 million; 2016 – $4,742 million, $1,623 million and $1,400 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 B) Revenues by Product Upstream Crude Oil Natural Gas NGLs Other Refined Product Market Optimization Corporate and Eliminations C) Geographical Information For the years ended December 31, Canada United States Consolidated As at December 31, Canada (2) United States Consolidated assets held for sale in current assets. Export Sales Major Customers As at December 31, Oil Sands Deep Basin Refining and Marketing Corporate and Eliminations Consolidated As at December 31, Oil Sands Deep Basin Conventional Refining and Marketing Corporate and Eliminations Consolidated E&E Assets 2018 639 146 - - 2017 617 3,056 - - PP&E 2018 21,646 2,482 4,284 286 2017 22,320 3,019 3,967 290 785 3,673 28,698 29,596 Goodwill 2018 2,272 - - - - 2017 2,272 - - - - Total Assets 2018 25,373 2,742 14 5,621 1,424 2017 26,799 6,694 644 5,432 1,364 2,272 2,272 35,174 40,933 E) Capital Expenditures (1) For the years ended December 31, Capital Investment Oil Sands Deep Basin Conventional Refining and Marketing Corporate and Eliminations Acquisition Capital Oil Sands (2) Deep Basin Total Capital Expenditures 2018 2017 2016 887 211 - 208 57 1,363 332 9 1,704 973 225 206 180 77 1,661 11,614 6,774 20,049 604 - 171 220 31 1,026 11 - 1,037 (1) (2) Includes expenditures on PP&E, E&E assets and assets held for sale. In connection with the acquisition discussed in Note 9, Cenovus was deemed to have disposed of its pre-existing interest in FCCL Partnership (“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 $11,605 million as at May 17, 2017. 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ 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 12, 2019. 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 discussed in Note 9, 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. 2018 ANNUAL REPORT | 75 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 (Loss). C) Revenue Recognition Policy Applicable From January 1, 2018 Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer. 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 services provided as agent are recorded as the services are provided. Cenovus recognizes revenue from the following major products and services: • • • • Sale of crude oil, natural gas and NGLs; Sale of petroleum and refined products; Marketing and transportation services; and Fee-for-service hydrocarbon trans-loading services. The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, natural gas, NGLs and petroleum and refined products, which is generally at a point in time. Performance obligations for marketing, transportation services and trans-loading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, natural gas, NGLs and petroleum and refined products pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period. Fees associated with marketing, transportation services and trans-loading services are based on fixed price contracts. Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with unfulfilled performance obligations. Policy Applicable Before January 1, 2018 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. 76 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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. 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 (Loss). C) Revenue Recognition Policy Applicable From January 1, 2018 Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer. 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 services provided as agent are recorded as the services are provided. Cenovus recognizes revenue from the following major products and services: • • • • Sale of crude oil, natural gas and NGLs; Sale of petroleum and refined products; Marketing and transportation services; and Fee-for-service hydrocarbon trans-loading services. The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, natural gas, NGLs and petroleum and refined products, which is generally at a point in time. Performance obligations for marketing, transportation services and trans-loading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, natural gas, NGLs and petroleum and refined products pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period. Fees associated with marketing, transportation services and trans-loading services are based on fixed price contracts. Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with unfulfilled performance obligations. Policy Applicable Before January 1, 2018 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 blending, are recognized when the product is sold. E) Exploration Expense The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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. 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. 2018 ANNUAL REPORT | 77 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 or the future economic value has decreased. 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 5 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. 78 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Other Assets Costs associated with the crude-by-rail terminal, infrastructure, 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 60 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 of 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 (Loss) 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. 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 or the future economic value has decreased. 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 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 5 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Other Assets Costs associated with the crude-by-rail terminal, infrastructure, 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 60 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 of 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 (Loss) 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. 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. 2018 ANNUAL REPORT | 79 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 (Loss). 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. Onerous Contract Provisions Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit- adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss). 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. assets. R) Stock-Based Compensation 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. 80 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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, short-term borrowings, contingent payment, risk management liabilities, 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. 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. Classification and Measurement of Financial Assets Policy Applicable From January 1, 2018 • • • • • • The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets: Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest; FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest; or Fair Value through Profit and Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis. At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings. Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model. 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. Policy Applicable Before January 1, 2018 Prior to the adoption of IFRS 9, “Financial Instruments” (“IFRS 9”) on January 1, 2018, the Company classified and measured financial assets under IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). There were three measurement categories into which the Company classified its financial assets: FVTPL: Assets were either ‘held-for-trading’ or had been ‘designated at fair value through profit or loss’. The assets were measured at fair value with changes in fair value recognized in net earnings; Loans and Receivables: Included assets with fixed or determinable payments that are not quoted in an active market. After initial measurements, these assets were measured at amortized cost at the settlement date using the effective interest rate method of amortization; and Available for Sale Financial Assets: Included investments in the equity of private companies that the Company did not have control or had significant influence over. These assets were measured at fair value, with changes in fair value recognized in OCI. When an active market was non-existent, fair value was determined using valuation techniques. When the fair value could not be reliably measured, such assets were carried at cost. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 (Loss). 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 Actual expenditures incurred are charged against the accumulated liability. useful life of the related asset. Onerous Contract Provisions Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit- adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss). 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. R) Stock-Based Compensation 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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, short-term borrowings, contingent payment, risk management liabilities, 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. 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. Classification and Measurement of Financial Assets Policy Applicable From January 1, 2018 The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets: • • • Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest; FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest; or Fair Value through Profit and Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets. On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis. At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings. Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model. 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. Policy Applicable Before January 1, 2018 Prior to the adoption of IFRS 9, “Financial Instruments” (“IFRS 9”) on January 1, 2018, the Company classified and measured financial assets under IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). There were three measurement categories into which the Company classified its financial assets: • • • FVTPL: Assets were either ‘held-for-trading’ or had been ‘designated at fair value through profit or loss’. The assets were measured at fair value with changes in fair value recognized in net earnings; Loans and Receivables: Included assets with fixed or determinable payments that are not quoted in an active market. After initial measurements, these assets were measured at amortized cost at the settlement date using the effective interest rate method of amortization; and Available for Sale Financial Assets: Included investments in the equity of private companies that the Company did not have control or had significant influence over. These assets were measured at fair value, with changes in fair value recognized in OCI. When an active market was non-existent, fair value was determined using valuation techniques. When the fair value could not be reliably measured, such assets were carried at cost. 2018 ANNUAL REPORT | 81 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Impairment of Financial Assets Policy Applicable From January 1, 2018 The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component. Policy Applicable Before January 1, 2018 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. Classification and Measurement of Financial Liabilities A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable. Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings. 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, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows and a gain or loss is recorded in net earnings. Derivatives Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction. Risk management assets and liabilities are derivative financial instruments classified as measured at FVTPL 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 Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts. 82 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 T) Reclassification Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2018. 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, 2019 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates: 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 above recognition 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 and may be applied retrospectively or using a modified retrospective approach. The Company has selected to use the modified retrospective approach which does not require restatement of prior period financial information as the cumulative effect of applying the standard to prior periods is recorded as an adjustment to opening retained earnings. On initial adoption, Management has elected to use the following practical expedients permitted under the standard: Apply a single discount rate to a portfolio of leases with similar characteristics; Account for leases with a remaining term of less than 12 months as at January 1, 2019 as short-term Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the The use of hindsight in determining the lease term where the contract contains terms to extend or leases; underlying asset is of low dollar value; terminate the lease; and Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”), for onerous contracts instead of reassessing the ROU asset for impairment on January 1, 2019. On adoption of IFRS 16, the Company will recognize lease liabilities in relation to leases under the principles of the new standard measured at the present value of the remaining lease payments, discounted using the interest rate implicit in the lease or the Company’s incremental borrowing rate as at January 1, 2019. The associated ROU assets will be measured at the amount equal to the lease liability on January 1, 2019 less any amount previously recognized under IAS 37 for onerous contracts with no impact on retained earnings. Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of approximately $1.5 billion and $0.9 billion, respectively. Management has identified ROU assets and lease liabilities primarily related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the consolidated statement of earnings will be as follows: Lower general and administrative expenses, transportation and blending costs, operating costs, purchased product and property, plant and equipment expenditures; Higher finance expenses due to the interest recognized on the lease obligations; and Higher depreciation expense related to the ROU assets. The Company has reviewed office space contracts where the Company is the lessor and as a result of these assessments will recognize a $16 million net investment from these leases on January 1, 2019. • • • • • • • • 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 will not have a significant impact on the Consolidated Financial Statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Impairment of Financial Assets Policy Applicable From January 1, 2018 The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component. Policy Applicable Before January 1, 2018 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. Classification and Measurement of Financial Liabilities A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable. Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings. 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, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows and a gain or loss is recorded in net earnings. Derivatives Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction. Risk management assets and liabilities are derivative financial instruments classified as measured at FVTPL 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 Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 T) Reclassification Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2018. 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, 2019 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates: 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 above recognition 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 and may be applied retrospectively or using a modified retrospective approach. The Company has selected to use the modified retrospective approach which does not require restatement of prior period financial information as the cumulative effect of applying the standard to prior periods is recorded as an adjustment to opening retained earnings. On initial adoption, Management has elected to use the following practical expedients permitted under the standard: • • • • • Apply a single discount rate to a portfolio of leases with similar characteristics; Account for leases with a remaining term of less than 12 months as at January 1, 2019 as short-term leases; Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the underlying asset is of low dollar value; The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the lease; and Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”), for onerous contracts instead of reassessing the ROU asset for impairment on January 1, 2019. On adoption of IFRS 16, the Company will recognize lease liabilities in relation to leases under the principles of the new standard measured at the present value of the remaining lease payments, discounted using the interest rate implicit in the lease or the Company’s incremental borrowing rate as at January 1, 2019. The associated ROU assets will be measured at the amount equal to the lease liability on January 1, 2019 less any amount previously recognized under IAS 37 for onerous contracts with no impact on retained earnings. Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of approximately $1.5 billion and $0.9 billion, respectively. Management has identified ROU assets and lease liabilities primarily related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the consolidated statement of earnings will be as follows: • • • Lower general and administrative expenses, transportation and blending costs, operating costs, purchased product and property, plant and equipment expenditures; Higher finance expenses due to the interest recognized on the lease obligations; and Higher depreciation expense related to the ROU assets. The Company has reviewed office space contracts where the Company is the lessor and as a result of these assessments will recognize a $16 million net investment from these leases on January 1, 2019. 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 will not have a significant impact on the Consolidated Financial Statements. 2018 ANNUAL REPORT | 83 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 4. CHANGES IN ACCOUNTING POLICIES A) Adoption of IFRS 9, “Financial Instruments” Effective January 1, 2018, the Company adopted IFRS 9, which replaced IAS 39. The Company applied the new standard retrospectively and, in accordance with the transitional provisions, comparative figures have not been restated. The adoption of IFRS 9 did not have a material impact on the Company’s Consolidated Financial Statements. The nature and effects of the key changes to the Company’s accounting policies resulting from the adoption of IFRS 9 are summarized below. Classification of Financial Assets and Financial Liabilities IFRS 9 contains three principal classification categories for financial assets: measured at amortized cost, FVOCI, and FVTPL. The previous IAS 39 categories of held to maturity, loans and receivables and available for sale are eliminated. IFRS 9 bases the classification of financial assets on the contractual cash flow characteristics and the Company’s business model for managing the financial asset. Additionally, embedded derivatives are not separated if the host contract is a financial asset within the scope of IFRS 9. Instead, the entire hybrid contract is assessed for classification and measurement. IFRS 9 largely retains the existing requirements in IAS 39 for the classification of financial liabilities. The differences between the two standards did not impact the Company at the time of transition. Impairment of Financial Assets IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ECL model. The new impairment model applies to financial assets measured at amortized cost, contract assets and debt investments measured at FVOCI. Under IFRS 9, credit losses will be recognized earlier than under IAS 39. Transition On January 1, 2018, the Company: • • • Identified the business model used to manage its financial assets and classified its financial instruments into the appropriate IFRS 9 category; Designated certain investments in private equity instruments, that were previously classified as available for sale, as FVOCI; and Applied the ECL model to financial assets classified as measured at amortized cost. The classification and measurement of financial instruments under IFRS 9 did not have a material impact on the Company’s opening retained earnings as at January 1, 2018. In addition, the application of the ECL model to financial assets classified as measured at amortized cost did not result in a material adjustment on transition. The following table shows the original measurement categories under IAS 39 and the new measurement categories under IFRS 9 as at January 1, 2018 for each class of the Company’s financial assets and financial liabilities. The Company has no contract assets or debt investments measured at FVOCI. Financial Instrument Cash and Cash Equivalents Accounts Receivable and Accrued Revenues Risk Management Assets Equity Investments Long-Term Receivables Accounts Payable and Accrued Liabilities Risk Management Liabilities Contingent Payment Short-Term Borrowings Long-Term Debt Measurement Category (1) IAS 39 Loans and Receivables Loans and Receivables FVTPL Available for Sale Financial Assets Loans and Receivables Financial Liabilities Measured at Amortized Cost FVTPL FVTPL Financial Liabilities Measured at Amortized Cost Financial Liabilities Measured at Amortized Cost IFRS 9 Amortized Cost Amortized Cost FVTPL FVOCI Amortized Cost Amortized Cost FVTPL FVTPL Amortized Cost Amortized Cost (1) There were no adjustments to the carrying amounts of financial instruments as a result of the change in classification from IAS 39 to IFRS 9. B) Adoption of IFRS 15, “Revenues From Contracts With Customers” Effective January 1, 2018, the Company adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. Cenovus adopted IFRS 15 using the modified retrospective with cumulative effect approach using the following practical expedients: • • Electing to apply the standard retrospectively only to contracts that were not completed contracts on January 1, 2018; and For modified contracts, evaluating the original contract together with any contract modifications at the date of initial application. 84 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 The adoption of IFRS 15 did not materially impact the timing or measurement of revenue. However, IFRS 15 contains new disclosure requirements. 5. 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 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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 4. CHANGES IN ACCOUNTING POLICIES A) Adoption of IFRS 9, “Financial Instruments” Effective January 1, 2018, the Company adopted IFRS 9, which replaced IAS 39. The Company applied the new standard retrospectively and, in accordance with the transitional provisions, comparative figures have not been restated. The adoption of IFRS 9 did not have a material impact on the Company’s Consolidated Financial Statements. IFRS 9 are summarized below. The nature and effects of the key changes to the Company’s accounting policies resulting from the adoption of Classification of Financial Assets and Financial Liabilities IFRS 9 contains three principal classification categories for financial assets: measured at amortized cost, FVOCI, and FVTPL. The previous IAS 39 categories of held to maturity, loans and receivables and available for sale are eliminated. IFRS 9 bases the classification of financial assets on the contractual cash flow characteristics and the Company’s business model for managing the financial asset. Additionally, embedded derivatives are not separated if the host contract is a financial asset within the scope of IFRS 9. Instead, the entire hybrid contract is assessed for classification and measurement. Impairment of Financial Assets IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ECL model. The new impairment model applies to financial assets measured at amortized cost, contract assets and debt investments measured at FVOCI. Under IFRS 9, credit losses will be recognized earlier than under IAS 39. Transition On January 1, 2018, the Company: • • • into the appropriate IFRS 9 category; for sale, as FVOCI; and Identified the business model used to manage its financial assets and classified its financial instruments Applied the ECL model to financial assets classified as measured at amortized cost. The classification and measurement of financial instruments under IFRS 9 did not have a material impact on the Company’s opening retained earnings as at January 1, 2018. In addition, the application of the ECL model to financial assets classified as measured at amortized cost did not result in a material adjustment on transition. The following table shows the original measurement categories under IAS 39 and the new measurement categories under IFRS 9 as at January 1, 2018 for each class of the Company’s financial assets and financial liabilities. The Company has no contract assets or debt investments measured at FVOCI. Accounts Payable and Accrued Liabilities Financial Liabilities Measured at Amortized Cost Measurement Category (1) IAS 39 Loans and Receivables Loans and Receivables FVTPL Available for Sale Financial Assets Loans and Receivables FVTPL FVTPL IFRS 9 Amortized Cost Amortized Cost FVTPL FVOCI FVTPL FVTPL Amortized Cost Amortized Cost Accounts Receivable and Accrued Revenues Financial Instrument Cash and Cash Equivalents Risk Management Assets Equity Investments Long-Term Receivables Risk Management Liabilities Contingent Payment Short-Term Borrowings Long-Term Debt practical expedients: • • January 1, 2018; and date of initial application. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 The adoption of IFRS 15 did not materially impact the timing or measurement of revenue. However, IFRS 15 contains new disclosure requirements. 5. 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. IFRS 9 largely retains the existing requirements in IAS 39 for the classification of financial liabilities. The differences between the two standards did not impact the Company at the time of transition. Joint Arrangements Designated certain investments in private equity instruments, that were previously classified as available In determining the classification of its joint arrangements under IFRS 11, the Company considered the following: 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, “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. • • • • • 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. Financial Liabilities Measured at Amortized Cost Financial Liabilities Measured at Amortized Cost Amortized Cost Amortized Cost Exploration and Evaluation Assets (1) There were no adjustments to the carrying amounts of financial instruments as a result of the change in classification from IAS 39 to IFRS 9. B) Adoption of IFRS 15, “Revenues From Contracts With Customers” Effective January 1, 2018, the Company adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. Cenovus adopted IFRS 15 using the modified retrospective with cumulative effect approach using the following 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. Electing to apply the standard retrospectively only to contracts that were not completed contracts on Identification of Cash-Generating Units For modified contracts, evaluating the original contract together with any contract modifications at the 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 2018 ANNUAL REPORT | 85 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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. 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. Onerous Contract Provisions A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed the economic benefits expected to be derived from the contract. Determining when to record a provision for an onerous contract requires Management judgment and the use of estimates and assumptions, including the nature, extent and timing of future cash flows and discount rates related to the contract. 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. 86 | CENOVUS ENERGY 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. 6. FINANCE COSTS For the years ended December 31, Interest Expense – Short-Term Borrowings and Long-Term Debt Premium (Discount) on Redemption of Long-Term Debt (Note 22) Unwinding of Discount on Decommissioning Liabilities (Note 25) Other 7. FOREIGN EXCHANGE (GAIN) LOSS, NET For the years ended December 31, 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 2018 516 17 62 32 627 2017 571 - 48 26 645 2016 341 - 28 21 390 2018 2017 2016 602 47 649 205 854 (665 ) (192 ) (857 ) 45 (812 ) (196 ) 7 (189 ) (9 ) (198 ) 8. DIVESTITURES On September 6, 2018, the Company completed the sale of Cenovus Pipestone Partnership (“CPP”), a wholly- owned subsidiary, for cash proceeds of $625 million, before closing adjustments. CPP held the Company’s Pipestone and Wembley natural gas and liquids business in northwestern Alberta and included the Company’s 39 percent operated working interest in the Wembley gas plant. A before-tax loss of $797 million was recorded on the sale (after-tax – $557 million). 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. For additional divestitures related to discontinued operations see Note 11. 9. ACQUISITION FCCL and Deep Basin Acquisition A) Summary of the Acquisition On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) a 50 percent interest in FCCL and the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). The acquisition from ConocoPhillips (the “Acquisition”) provided Cenovus with control over the Company’s oil sands operations, doubled the Company’s oil sands production, and almost doubled the Company’s proved bitumen reserves. The Deep Basin Assets provide short- cycle development opportunities with high-return potential 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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. 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. Onerous Contract Provisions A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed the economic benefits expected to be derived from the contract. Determining when to record a provision for an onerous contract requires Management judgment and the use of estimates and assumptions, including the nature, extent and timing of future cash flows and discount rates related to the contract. 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. 6. FINANCE COSTS For the years ended December 31, Interest Expense – Short-Term Borrowings and Long-Term Debt Premium (Discount) on Redemption of Long-Term Debt (Note 22) Unwinding of Discount on Decommissioning Liabilities (Note 25) Other 7. FOREIGN EXCHANGE (GAIN) LOSS, NET For the years ended December 31, 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 2018 516 17 62 32 627 2017 571 - 48 26 645 2016 341 - 28 21 390 2018 2017 2016 602 47 649 205 854 (665 ) (192 ) (857 ) 45 (812 ) (196 ) 7 (189 ) (9 ) (198 ) 8. DIVESTITURES On September 6, 2018, the Company completed the sale of Cenovus Pipestone Partnership (“CPP”), a wholly- owned subsidiary, for cash proceeds of $625 million, before closing adjustments. CPP held the Company’s Pipestone and Wembley natural gas and liquids business in northwestern Alberta and included the Company’s 39 percent operated working interest in the Wembley gas plant. A before-tax loss of $797 million was recorded on the sale (after-tax – $557 million). 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. For additional divestitures related to discontinued operations see Note 11. 9. ACQUISITION FCCL and Deep Basin Acquisition A) Summary of the Acquisition On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) a 50 percent interest in FCCL and the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). The acquisition from ConocoPhillips (the “Acquisition”) provided Cenovus with control over the Company’s oil sands operations, doubled the Company’s oil sands production, and almost doubled the Company’s proved bitumen reserves. The Deep Basin Assets provide short- cycle development opportunities with high-return potential 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. 2018 ANNUAL REPORT | 87 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 B) Identifiable Assets Acquired and Liabilities Assumed D) Goodwill The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of the Acquisition. Goodwill arising from the Acquisition has been recognized as follows: 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 C) Total Consideration Notes 880 964 345 17 18 491 22,717 25 17 18 25 27 (445 ) (277 ) (8 ) (2,506 ) 22,188 16 14 3,117 3,600 (6 ) (667 ) 6,074 28,262 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 considerations: Common Shares Cash Estimated Contingent Payment (Note 23) 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 28) and an offering in the United States for senior unsecured notes (see Note 22). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see Note 22). 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 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 is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (see Note 23). 88 | CENOVUS ENERGY Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL Fair Value of Identifiable Net Assets Goodwill Notes 9C 9B (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 In 2017, 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 In 2017, costs related to the transitional services of approximately $40 million were recorded in general and amounts. administrative 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. 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. For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. 2018 Net Upstream Impairments As at December 31, 2018, the book value of the Company’s net assets was greater than its market capitalization; therefore, the Company tested its upstream CGUs for impairment. As at December 31, 2018, there was no impairment of goodwill or the Company’s CGUs. However, the impairment test provided evidence that previously recognized impairment losses should be reversed. As at December 31, 2018, the recoverable amount of the Clearwater CGU was estimated to be $761 million. Earlier in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline in forward prices. The impairment was recorded as additional DD&A in the Deep Basin segment. In the fourth NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 B) Identifiable Assets Acquired and Liabilities Assumed D) Goodwill The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of Goodwill arising from the Acquisition has been recognized as follows: Notes 17 18 25 17 18 25 880 964 345 491 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 17,945 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL Accounts Receivable and Accrued Revenues Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin Accounts Receivable and Accrued Revenues 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 C) Total Consideration Common Shares Cash Estimated Contingent Payment (Note 23) 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 considerations: 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 28) and an offering in the United States for senior unsecured notes (see Note 22). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see Note 22). 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 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 is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (see Note 23). Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL Fair Value of Identifiable Net Assets Goodwill Notes 9C 17,945 12,347 9B (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. E) Acquisition-Related Costs In 2017, 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. In 2017, 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. 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. For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. 2018 Net Upstream Impairments As at December 31, 2018, the book value of the Company’s net assets was greater than its market capitalization; therefore, the Company tested its upstream CGUs for impairment. As at December 31, 2018, there was no impairment of goodwill or the Company’s CGUs. However, the impairment test provided evidence that previously recognized impairment losses should be reversed. As at December 31, 2018, the recoverable amount of the Clearwater CGU was estimated to be $761 million. Earlier in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline in forward prices. The impairment was recorded as additional DD&A in the Deep Basin segment. In the fourth 2018 ANNUAL REPORT | 89 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 quarter of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal was due to improved recovery, extensions, and well performance and changes to the development plan. There were no goodwill impairments for the twelve months ended December 31, 2018. Key Assumptions The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after- tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2018 by the IQREs. Crude Oil, NGLs and Natural Gas Prices The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) (1) Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units (“MMBtu”) per thousand cubic feet. 2.1 % 2.0 % 2.0 % 2.0 % 2019 58.58 51.55 70.10 1.88 2020 64.60 59.58 79.21 2.31 2021 68.20 65.89 83.33 2.74 2023 72.81 70.53 88.16 3.21 2022 71.00 68.61 86.20 3.05 Average Annual Increase Thereafter 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. 2017 Upstream Impairments As at December 31, 2017, the Company tested its Clearwater CGU for impairment due to a decline in forward commodity prices. As a result, an impairment loss of $56 million on the Clearwater CGU was recorded. The impairment was recorded as additional DD&A in the Deep Basin segment. As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately $295 million, which excludes the Clearwater assets reclassified to assets held for sale. There were no goodwill impairments for the twelve months ended December 31, 2017. Key Assumptions The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Forward prices as at December 31, 2017 used to determine future cash flows from crude oil and natural gas reserves were: WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) 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 90 | CENOVUS ENERGY Average Annual Increase Thereafter 2.1 % 2.1 % 2.1 % 2.0 % 2022 71.19 66.63 83.32 3.67 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 2016 Net Upstream Impairments As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion. Previously, impairment losses of $564 million were recorded primarily 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. 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 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. The Suffield CGU includes 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. B) Asset Impairments and Write-downs Exploration and Evaluation Assets In the fourth quarter of 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. As such, previously capitalized E&E costs of $2.1 billion were written off as exploration expense in the Elmworth, Wapiti, Kaybob, Edson and Clearwater areas within the Deep Basin segment. For the year ended December 31, 2017, Management wrote off certain E&E assets, as their carrying values were not considered to be recoverable. As a result, $888 million of previously capitalized E&E costs were written off and 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 In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the of these projects. Oil Sands segment. Property, Plant and Equipment, Net For the year ended December 31, 2018, the Company recorded an impairment loss of $6 million in the Oil Sands segment for information technology assets that were written down to their recoverable amounts. 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. 11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS In 2017, the Company announced its intention to divest of its Conventional segment and market for sale a package of the Company’s non-core Deep Basin assets in the East Clearwater and a portion of the West Clearwater area. The Conventional segment included the Company’s heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were reclassified as held for sale. The results of operations from the Conventional segment have been reported as a discontinued operation. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 quarter of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal was due to improved recovery, extensions, and well performance and changes to the development plan. There were no goodwill impairments for the twelve months ended December 31, 2018. Key Assumptions The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after- tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2018 by the IQREs. Crude Oil, NGLs and Natural Gas Prices gas reserves were: The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural 2019 58.58 51.55 70.10 1.88 2020 64.60 59.58 79.21 2.31 2021 68.20 65.89 83.33 2.74 2022 71.00 68.61 86.20 3.05 2023 Thereafter 72.81 70.53 88.16 3.21 2.0 % 2.1 % 2.0 % 2.0 % Average Annual Increase WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) (1) Discount and Inflation Rates two percent. 2017 Upstream Impairments (1) Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units (“MMBtu”) 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 As at December 31, 2017, the Company tested its Clearwater CGU for impairment due to a decline in forward commodity prices. As a result, an impairment loss of $56 million on the Clearwater CGU was recorded. The impairment was recorded as additional DD&A in the Deep Basin segment. As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately $295 million, which excludes the Clearwater assets reclassified to assets held for sale. There were no goodwill impairments for the twelve months ended December 31, 2017. Key Assumptions The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Forward prices as at December 31, 2017 used to determine future cash flows from crude oil and natural gas reserves were: WTI (US$/barrel) WCS (C$/barrel) Edmonton C5+ (C$/barrel) AECO (C$/Mcf) 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 2022 Thereafter 71.19 66.63 83.32 3.67 2.1 % 2.1 % 2.1 % 2.0 % Average Annual Increase NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 2016 Net Upstream Impairments As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion. Previously, impairment losses of $564 million were recorded primarily 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. 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 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. The Suffield CGU includes 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. B) Asset Impairments and Write-downs Exploration and Evaluation Assets In the fourth quarter of 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. As such, previously capitalized E&E costs of $2.1 billion were written off as exploration expense in the Elmworth, Wapiti, Kaybob, Edson and Clearwater areas within the Deep Basin segment. For the year ended December 31, 2017, Management wrote off certain E&E assets, as their carrying values were not considered to be recoverable. As a result, $888 million of previously capitalized E&E costs were written off and 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. Property, Plant and Equipment, Net For the year ended December 31, 2018, the Company recorded an impairment loss of $6 million in the Oil Sands segment for information technology assets that were written down to their recoverable amounts. 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. 11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS In 2017, the Company announced its intention to divest of its Conventional segment and market for sale a package of the Company’s non-core Deep Basin assets in the East Clearwater and a portion of the West Clearwater area. The Conventional segment included the Company’s heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were reclassified as held for sale. The results of operations from the Conventional segment have been reported as a discontinued operation. 2018 ANNUAL REPORT | 91 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 A) Assets and Liabilities Held for Sale The Conventional segment and non-core Deep Basin assets were 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. In December 2018, Management decided to discontinue the Clearwater assets sale process. While discussions with prospective purchasers have occurred, an offer that meets Management’s expectations has not been received. As a result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion, calculated on a per-unit of production basis, was recorded in the fourth quarter. There was no impairment of the assets prior to reclassification. As at December 31, 2018, no assets were classified as held for sale. As at December 31, 2017 Conventional Deep Basin B) Results of Discontinued Operations E&E Assets - 46 46 PP&E 568 434 1,002 Decommissioning Liabilities 454 149 603 On January 5, 2018, the Company completed the sale of its Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of $343 million was recorded on the sale. 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 two years following the close of the disposition. The DPPA is a two year agreement that commenced 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 MMBtu. 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. In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of $3.2 billion before closing adjustments. A before-tax gain on discontinuance of $1.3 billion was recorded on the sale. The following table presents the results of discontinued operations, including asset sales: For the years ended December 31, 2018 2017 2016 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 $81 million in 2018 (2017 – $347 million). 14 3 11 1 (28 ) 1 - 37 - - 1 36 - 9 27 220 247 1,309 174 1,135 1,267 139 1,128 167 426 18 33 491 192 2 80 217 24 33 160 938 1,098 186 444 12 (58 ) 544 567 - 102 (125 ) 86 (125 ) (86 ) - (86 ) 92 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 C) 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 (Used in) Operating Activities Cash From (Used in) Investing Activities Net Cash Flow 12. INCOME TAXES The provision for income taxes is: For the years ended December 31, Current Tax Canada United States Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Tax Expense (Recovery) From Continuing Operations 2018 36 404 440 2017 448 2,993 3,441 2016 435 (168 ) 267 2018 2017 2016 (128 ) 2 (126 ) (884 ) (1,010 ) (217 ) (38 ) (255 ) 203 (52 ) (260 ) 1 (259 ) (84 ) (343 ) In 2018, 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax purposes and prior year adjustments. The maximum recovery was reached in 2018. In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down of the Deep Basin E&E assets, and $78 million arising from an adjustment to the tax basis of the Company’s 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. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, net of a 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 write-downs. 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 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 2018 (3,926 ) 27.0 % (1,060 ) (57 ) 82 99 3 - (78 ) - 2 (1 ) (1,010 ) 25.7 % 2017 2,216 27.0 % 598 (17 ) (129 ) (99 ) (41 ) (68 ) - (275 ) (5 ) (16 ) (52 ) (2.3) % 2016 (802 ) 27.0 % (217 ) (46 ) (26 ) (26 ) (46 ) - - - 5 13 (343 ) 42.8 % NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 A) Assets and Liabilities Held for Sale The Conventional segment and non-core Deep Basin assets were 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. In December 2018, Management decided to discontinue the Clearwater assets sale process. While discussions with prospective purchasers have occurred, an offer that meets Management’s expectations has not been received. As a result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion, calculated on a per-unit of production basis, was recorded in the fourth quarter. There was no impairment of the assets prior to reclassification. As at December 31, 2018, no assets were classified as held for sale. As at December 31, 2017 Conventional Deep Basin B) Results of Discontinued Operations E&E Assets PP&E Liabilities Decommissioning - 46 46 568 434 1,002 454 149 603 On January 5, 2018, the Company completed the sale of its Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of $343 million was recorded on the sale. 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 two years following the close of the disposition. The DPPA is a two year agreement that commenced 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 MMBtu. 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. In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of $3.2 billion before closing adjustments. A before-tax gain on discontinuance of $1.3 billion was recorded on the The following table presents the results of discontinued operations, including asset sales: For the years ended December 31, 2018 2017 2016 sale. 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 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 $81 million in 2018 (2017 – $347 million). 14 3 11 1 (28 ) 1 - 37 - - 1 36 - 9 27 220 247 1,309 174 1,135 1,267 139 1,128 167 426 18 33 491 192 2 80 217 24 33 160 938 1,098 186 444 12 (58 ) 544 567 - 102 (125 ) 86 (125 ) (86 ) - (86 ) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 C) 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 (Used in) Operating Activities Cash From (Used in) Investing Activities Net Cash Flow 12. INCOME TAXES The provision for income taxes is: For the years ended December 31, Current Tax Canada United States Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Tax Expense (Recovery) From Continuing Operations 2018 36 404 440 2017 448 2,993 3,441 2016 435 (168 ) 267 2018 2017 2016 (128 ) 2 (126 ) (884 ) (1,010 ) (217 ) (38 ) (255 ) 203 (52 ) (260 ) 1 (259 ) (84 ) (343 ) In 2018, 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax purposes and prior year adjustments. The maximum recovery was reached in 2018. In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down of the Deep Basin E&E assets, and $78 million arising from an adjustment to the tax basis of the Company’s 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. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, net of a 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 write-downs. 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 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 2018 (3,926 ) 27.0 % (1,060 ) (57 ) 82 99 3 - (78 ) - 2 (1 ) (1,010 ) 25.7 % 2017 2,216 27.0 % 598 (17 ) (129 ) (99 ) (41 ) (68 ) - (275 ) (5 ) (16 ) (52 ) (2.3) % 2016 (802 ) 27.0 % (217 ) (46 ) (26 ) (26 ) (46 ) - - - 5 13 (343 ) 42.8 % 2018 ANNUAL REPORT | 93 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 The analysis of deferred income tax liabilities and deferred income tax assets is as follows: The approximate amounts of tax pools available, including tax losses, are: For the years ended December 31, Deferred Income Tax Liabilities Deferred Income Tax Liabilities to be Settled Within 12 Months Deferred Income Tax Liabilities to be Settled After More Than 12 Months Deferred Income Tax Assets Deferred Income Tax Assets to be Recovered Within 12 Months Deferred Income Tax Assets to be Recovered After More Than 12 Months Net Deferred Income Tax Liability 2018 2017 47 5,498 5,545 (57 ) (627 ) (684 ) 4,861 186 6,229 6,415 (374 ) (428 ) (802 ) 5,613 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. The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is: Deferred Income Tax Liabilities As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Purchase Price Allocation Charged (Credited) to OCI As at December 31, 2017 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2018 Deferred Income Tax Assets As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Share Capital Charged (Credited) to OCI As at December 31, 2017 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2018 Timing of Partnership Risk Items - 164 Management 6 11 Other 1 1 PP&E 3,146 625 2,506 (45 ) 6,232 (836 ) 54 5,450 - - 164 (164 ) - - - - 17 27 - 44 Unused Tax Timing of Partnership Risk Losses (270 ) 67 - 12 (191 ) (159 ) (7 ) (357 ) Items - - - - - - - - Management (85 ) (198 ) - - (283 ) 282 - (1 ) - - 2 49 - 51 Other (213 ) (87 ) (28 ) - (328 ) 8 (6 ) (326 ) Net Deferred Income Tax Liabilities 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 Charged (Credited) to Earnings Charged (Credited) to OCI Net Deferred Income Tax Liabilities as at December 31, 2018 Total 3,153 801 2,506 (45 ) 6,415 (924 ) 54 5,545 Total (568 ) (218 ) (28 ) 12 (802 ) 131 (13 ) (684 ) Total 2,585 583 2,506 (28 ) (33 ) 5,613 (793 ) 41 4,861 No deferred tax liability has been recognized as at December 31, 2018 and 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. 94 | CENOVUS ENERGY As at December 31, Canada United States earlier than 2033. As at December 31, 2018, the above tax pools included $1,375 million (2017 – $73 million) of Canadian federal non-capital losses and $nil (2017 – $593 million) of U.S. federal net operating losses. These losses expire no Also included in the December 31, 2018 tax pools are Canadian net capital losses totaling $8 million (2017 – $8 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, 2018 (2017 – $8 million). Recognition is dependent on future capital gains. The Company has not recognized $661 million (2017 – $293 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt. 2018 7,935 1,391 9,326 2017 8,317 1,714 10,031 13. PER SHARE AMOUNTS A) Net Earnings (Loss) Per Share — Basic and Diluted For the years ended December 31, Earnings (Loss) From: Continuing Operations Discontinued Operations Net Earnings (Loss) Basic - Weighted Average Number of Shares (millions) Dilutive Effect of Cenovus NSRs Diluted - Weighted Average Number of Shares Basic and Diluted Earnings (Loss) Per Share From: ($) Continuing Operations Discontinued Operations Net Earnings (Loss) Per Share 2018 2017 2016 (2,916 ) 247 (2,669 ) 2,268 1,098 3,366 1,228.8 1,102.5 0.4 - 1,229.2 1,102.5 (2.37 ) 0.20 (2.17 ) 2.06 0.99 3.05 (459 ) (86 ) (545 ) 833.3 - 833.3 (0.55 ) (0.10 ) (0.65 ) As at December 31, 2018, 34 million NSRs (2017 – 43 million; 2016 – 42 million) and no TSARs (2017 – 81 thousand; 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 30. B) Dividends Per Share For the year ended December 31, 2018, the Company paid cash dividends of $245 million or $0.20 per share, all of which were paid in cash (2017 – $225 million or $0.20 per share; 2016 – $166 million or $0.20 per share). The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2019, to common shareholders of record as of March 15, 2019. 14. CASH AND CASH EQUIVALENTS As at December 31, Cash Short-Term Investments 2018 155 626 781 2017 547 63 610 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 For the years ended December 31, Deferred Income Tax Liabilities Deferred Income Tax Liabilities to be Settled Within 12 Months Deferred Income Tax Liabilities to be Settled After More Than 12 Months Deferred Income Tax Assets Deferred Income Tax Assets to be Recovered Within 12 Months Deferred Income Tax Assets to be Recovered After More Than 12 Months Net Deferred Income Tax Liability 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. balances within the same tax jurisdiction, is: Deferred Income Tax Liabilities As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Purchase Price Allocation Charged (Credited) to OCI As at December 31, 2017 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2018 Deferred Income Tax Assets As at December 31, 2016 Charged (Credited) to Earnings Charged (Credited) to Share Capital Charged (Credited) to OCI As at December 31, 2017 Charged (Credited) to Earnings Charged (Credited) to OCI As at December 31, 2018 Timing of Partnership Risk Items Management Other - 164 - - 164 (164 ) - - - - - - - - - - 6 11 - - 17 27 - 44 (85 ) (198 ) - - (283 ) 282 - (1 ) 1 1 - - 2 49 - 51 Other (213 ) (87 ) (28 ) - (328 ) 8 (6 ) (326 ) PP&E 3,146 625 2,506 (45 ) 6,232 (836 ) 54 5,450 Losses (270 ) 67 - 12 (191 ) (159 ) (7 ) (357 ) Timing of Unused Tax Partnership Risk Items Management Net Deferred Income Tax Liabilities 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 Charged (Credited) to Earnings Charged (Credited) to OCI Net Deferred Income Tax Liabilities as at December 31, 2018 No deferred tax liability has been recognized as at December 31, 2018 and 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. Total 3,153 801 2,506 (45 ) 6,415 (924 ) 54 5,545 Total (568 ) (218 ) (28 ) 12 (802 ) 131 (13 ) (684 ) Total 2,585 583 2,506 (28 ) (33 ) 5,613 (793 ) 41 4,861 The analysis of deferred income tax liabilities and deferred income tax assets is as follows: The approximate amounts of tax pools available, including tax losses, are: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 2018 2017 47 5,498 5,545 (57 ) (627 ) (684 ) 4,861 186 6,229 6,415 (374 ) (428 ) (802 ) 5,613 As at December 31, Canada United States 2018 7,935 1,391 9,326 2017 8,317 1,714 10,031 As at December 31, 2018, the above tax pools included $1,375 million (2017 – $73 million) of Canadian federal non-capital losses and $nil (2017 – $593 million) of U.S. federal net operating losses. These losses expire no earlier than 2033. Also included in the December 31, 2018 tax pools are Canadian net capital losses totaling $8 million (2017 – $8 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, 2018 (2017 – $8 million). Recognition is dependent on future capital gains. The Company has not recognized $661 million (2017 – $293 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt. The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of 13. PER SHARE AMOUNTS A) Net Earnings (Loss) Per Share — Basic and Diluted For the years ended December 31, Earnings (Loss) From: Continuing Operations Discontinued Operations Net Earnings (Loss) Basic - Weighted Average Number of Shares (millions) Dilutive Effect of Cenovus NSRs Diluted - Weighted Average Number of Shares Basic and Diluted Earnings (Loss) Per Share From: ($) Continuing Operations Discontinued Operations Net Earnings (Loss) Per Share 2018 2017 2016 (2,916 ) 247 (2,669 ) 2,268 1,098 3,366 1,228.8 0.4 1,229.2 1,102.5 - 1,102.5 (2.37 ) 0.20 (2.17 ) 2.06 0.99 3.05 (459 ) (86 ) (545 ) 833.3 - 833.3 (0.55 ) (0.10 ) (0.65 ) As at December 31, 2018, 34 million NSRs (2017 – 43 million; 2016 – 42 million) and no TSARs (2017 – 81 thousand; 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 30. B) Dividends Per Share For the year ended December 31, 2018, the Company paid cash dividends of $245 million or $0.20 per share, all of which were paid in cash (2017 – $225 million or $0.20 per share; 2016 – $166 million or $0.20 per share). The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2019, to common shareholders of record as of March 15, 2019. 14. CASH AND CASH EQUIVALENTS As at December 31, Cash Short-Term Investments 2018 155 626 781 2017 547 63 610 2018 ANNUAL REPORT | 95 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES 18. PROPERTY, PLANT AND EQUIPMENT, NET As at December 31, Accruals Prepaids and Deposits Partner Advances Trade Joint Operations Receivables Other 16. INVENTORIES As at December 31, Product Refining and Marketing Oil Sands Deep Basin Conventional Parts and Supplies 2018 614 45 237 251 37 54 1,238 2017 1,379 64 94 193 51 49 1,830 2018 2017 703 223 - - 87 1,013 894 414 2 2 77 1,389 During the year ended December 31, 2018, approximately $15,664 million of produced and purchased inventory was recorded as an expense (2017 – $12,856 million; 2016 – $9,964 million). As a result of a decline in refined product prices, Cenovus recorded a write-down of its product inventory of $47 million from cost to net realizable value as at December 31, 2018. 17. EXPLORATION AND EVALUATION ASSETS As at December 31, 2016 Additions Acquisition (Note 9) (1) Transfers to Assets Held for Sale (Note 11) Transfers to PP&E (Note 18) Exploration Expense (Note 10) Change in Decommissioning Liabilities Other Divestitures (1) As at December 31, 2017 Additions Transfers to Assets Held for Sale (Note 11) Transfers from Assets Held for Sale (Note 11) Exploration Expense (Note 10) Change in Decommissioning Liabilities Divestitures As at December 31, 2018 Total 1,585 147 3,608 (316 ) (6 ) (890 ) 5 19 (479 ) 3,673 374 (1 ) 46 (2,123 ) (8 ) (1,176 ) 785 (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. PP&E includes the following amounts in respect of assets under construction and not subject to DD&A: 96 | CENOVUS ENERGY Upstream Assets Development Other Refining & Production Upstream Equipment Other (1) Total 333 5,259 168 1,074 89 28,046 333 5,632 - - - - - - - - - - - 333 - 308 23 - - - - 331 2 - - - - - - - - - (364 ) (2 ) 5,061 204 - (3 ) 370 - 1,076 209 - - (91 ) (1 ) 1,193 217 - - - 32 - COST As at December 31, 2016 Additions Acquisitions (Note 9) (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 (Notes 8 and 11) (2) As at December 31, 2017 Additions (Note 11) Transfers from Assets Held for Sale Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2018 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION 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 (Notes 8 and 11) (2) As at December 31, 2017 DD&A (Note 11) Transfers from Assets Held for Sale Impairment Losses (Note 10) Impairment Reversals (Note 10) Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2018 CARRYING VALUE As at December 31, 2016 As at December 31, 2017 As at December 31, 2018 31,941 1,324 26,317 6 (19,719 ) (67 ) (28 ) (12,333 ) 27,441 1,065 469 (279 ) (6 ) (644 ) 20,088 1,653 77 (16,120 ) 17 (3,611 ) 2,104 1,874 35 106 (132 ) (31 ) (38 ) As at December 31, Development and Production Refining Equipment 3,918 333 1,442 (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. 11,853 25,337 24,128 25 2 - 4,183 3,868 4,190 365 389 380 16,426 29,596 28,698 38,607 1,581 26,317 6 (19,719 ) (64 ) (391 ) (12,335 ) 34,002 1,330 469 (285 ) 364 (656 ) 35,224 22,181 1,953 77 (16,120 ) (73 ) (3,612 ) 4,406 2,157 35 106 (132 ) 1 (47 ) 6,526 - - - 3 1 - 1,167 61 - (3 ) - (12 ) 1,213 709 68 - - 1 - 778 64 - - - - (9 ) 833 2018 1,818 181 1,999 2017 1,809 131 1,940 As at December 31, Accruals Prepaids and Deposits Partner Advances Trade Other Joint Operations Receivables 16. INVENTORIES As at December 31, Product Refining and Marketing Oil Sands Deep Basin Conventional Parts and Supplies As at December 31, 2016 Additions Acquisition (Note 9) (1) Transfers to Assets Held for Sale (Note 11) Transfers to PP&E (Note 18) Exploration Expense (Note 10) Change in Decommissioning Liabilities Other Divestitures (1) As at December 31, 2017 Additions Transfers to Assets Held for Sale (Note 11) Transfers from Assets Held for Sale (Note 11) Exploration Expense (Note 10) Change in Decommissioning Liabilities Divestitures As at December 31, 2018 required by IFRS 3. During the year ended December 31, 2018, approximately $15,664 million of produced and purchased inventory was recorded as an expense (2017 – $12,856 million; 2016 – $9,964 million). As a result of a decline in refined product prices, Cenovus recorded a write-down of its product inventory of $47 million from cost to net realizable value as at December 31, 2018. 17. EXPLORATION AND EVALUATION ASSETS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES 18. PROPERTY, PLANT AND EQUIPMENT, NET 2018 614 45 237 251 37 54 2017 1,379 64 94 193 51 49 1,238 1,830 2018 2017 703 223 - - 87 894 414 2 2 77 1,013 1,389 Total 1,585 147 3,608 (316 ) (6 ) (890 ) 5 19 (479 ) 3,673 374 (1 ) 46 (2,123 ) (8 ) (1,176 ) 785 Upstream Assets Development & Production Other Upstream Refining Equipment Other (1) Total COST As at December 31, 2016 Additions Acquisitions (Note 9) (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 (Notes 8 and 11) (2) As at December 31, 2017 Additions Transfers from Assets Held for Sale (Note 11) Change in Decommissioning Liabilities Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2018 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION 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 (Notes 8 and 11) (2) As at December 31, 2017 DD&A Transfers from Assets Held for Sale (Note 11) Impairment Losses (Note 10) Impairment Reversals (Note 10) Exchange Rate Movements and Other Divestitures (Note 8) As at December 31, 2018 CARRYING VALUE As at December 31, 2016 As at December 31, 2017 As at December 31, 2018 31,941 1,324 26,317 6 (19,719 ) (67 ) (28 ) (12,333 ) 27,441 1,065 469 (279 ) (6 ) (644 ) 28,046 20,088 1,653 77 (16,120 ) 17 (3,611 ) 2,104 1,874 35 106 (132 ) (31 ) (38 ) 3,918 11,853 25,337 24,128 333 - - - - - - - 333 - - - - - 333 308 23 - - - - 331 2 - - - - - 333 5,259 168 - - - - (364 ) (2 ) 5,061 204 - (3 ) 370 - 5,632 1,076 209 - - (91 ) (1 ) 1,193 217 - - - 32 - 1,442 1,074 89 - - - 3 1 - 1,167 61 - (3 ) - (12 ) 1,213 709 68 - - 1 - 778 64 - - - - (9 ) 833 38,607 1,581 26,317 6 (19,719 ) (64 ) (391 ) (12,335 ) 34,002 1,330 469 (285 ) 364 (656 ) 35,224 22,181 1,953 77 (16,120 ) (73 ) (3,612 ) 4,406 2,157 35 106 (132 ) 1 (47 ) 6,526 25 2 - 4,183 3,868 4,190 365 389 380 16,426 29,596 28,698 (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. (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 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 2018 1,818 181 1,999 2017 1,809 131 1,940 2018 ANNUAL REPORT | 97 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 9) Carrying Value, End of Year 2018 2017 38 12 8 6 64 37 11 9 14 71 2018 2,272 - 2,272 2017 242 2,030 2,272 As at December 31, 2018 and 2017, the carrying amount of goodwill was associated with the Company’s Primrose (Foster Creek) CGU and Christina Lake CGU was $1,171 million and $1,101 million, respectively. 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, 2018 are consistent to those disclosed in Note 10. 21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, Accruals Trade Interest Partner Advances Employee Long-Term Incentives Joint Operations Payable Other 22. LONG-TERM DEBT AND CAPITAL STRUCTURE As at December 31, Revolving Term Debt (1) U.S. Dollar Denominated Unsecured Notes Total Debt Principal Debt Discounts and Transaction Costs Long-Term Debt Less: Current Portion Long-Term Portion 2018 675 767 80 237 36 3 35 1,833 2018 - 9,241 9,241 (77 ) 9,164 682 8,482 2017 2,006 337 86 94 52 12 40 2,627 2017 - 9,597 9,597 (84 ) 9,513 - 9,513 Notes A B (1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate (“LIBOR”) 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, 2018 was 5.1 percent (2017 – 4.9 percent). A) Revolving Term Debt Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche. On October 17, 2018, the Company extended the maturity date of the $1.2 billion tranche from November 30, 2020 to November 30, 2021 and the maturity date of the $3.3 billion tranche from November 30, 2021 to November 30, 2022. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at December 31, 2018, there were no amounts drawn on Cenovus’s committed credit facility (2017 – $nil). 2019 2020 2021 2022 2023 Thereafter 98 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 B) 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 2018 2017 US$ Principal Total C$ US$ Principal Amount Equivalent Amount Total C$ Equivalent 500 500 450 1,171 700 1,400 744 350 959 6,774 682 682 614 1,597 955 1,910 1,015 477 1,309 9,241 1,300 500 450 1,200 700 1,400 750 350 1,000 7,650 1,631 627 565 1,505 878 1,756 941 439 1,255 9,597 On October 29, 2018, the Company redeemed US$800 million of its US$1,300 million unsecured notes due October 15, 2019. A redemption premium of US$20 million and associated unamortized discount and debt issue costs of $1 million were recognized in 2018. In December 2018, the Company paid US$69 million to repurchase a portion of its unsecured notes with a principal amount of US$76 million. A gain on the repurchase of $9 million was recorded in finance costs. Subsequent to December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for cash of US$300 million (see Note 37). 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. The Company has in place 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. As at December 31, 2018, 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, 2018, the Company is in compliance with all of the terms of its debt agreements. C) Asset Sale Bridge Credit Facility In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017. D) Mandatory Debt Payments as at December 31, 2018 US$ Principal Amount Total C$ Equivalent 500 - - 500 450 5,324 6,774 682 - - 682 614 7,263 9,241 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 9) Carrying Value, End of Year 2018 2017 38 12 8 6 64 37 11 9 14 71 2018 2,272 - 2,272 2017 242 2,030 2,272 1,833 2,627 2018 675 767 80 237 36 3 35 2018 - 9,241 9,241 (77 ) 9,164 682 8,482 2017 2,006 337 86 94 52 12 40 2017 - 9,597 9,597 (84 ) 9,513 - 9,513 As at December 31, 2018 and 2017, the carrying amount of goodwill was associated with the Company’s Primrose (Foster Creek) CGU and Christina Lake CGU was $1,171 million and $1,101 million, respectively. 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, 2018 are consistent to those disclosed in Note 10. 21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, Accruals Trade Interest Partner Advances Employee Long-Term Incentives Joint Operations Payable Other As at December 31, Revolving Term Debt (1) U.S. Dollar Denominated Unsecured Notes Total Debt Principal Debt Discounts and Transaction Costs Long-Term Debt Less: Current Portion Long-Term Portion loans. (2017 – 4.9 percent). A) Revolving Term Debt 22. LONG-TERM DEBT AND CAPITAL STRUCTURE Notes A B NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 B) 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 2018 US$ Principal Amount 500 500 450 1,171 700 1,400 744 350 959 6,774 Total C$ Equivalent US$ Principal Amount Total C$ Equivalent 2017 682 682 614 1,597 955 1,910 1,015 477 1,309 9,241 1,300 500 450 1,200 700 1,400 750 350 1,000 7,650 1,631 627 565 1,505 878 1,756 941 439 1,255 9,597 On October 29, 2018, the Company redeemed US$800 million of its US$1,300 million unsecured notes due October 15, 2019. A redemption premium of US$20 million and associated unamortized discount and debt issue costs of $1 million were recognized in 2018. In December 2018, the Company paid US$69 million to repurchase a portion of its unsecured notes with a principal amount of US$76 million. A gain on the repurchase of $9 million was recorded in finance costs. Subsequent to December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for cash of US$300 million (see Note 37). 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. The Company has in place 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. As at December 31, 2018, 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, 2018, the Company is in compliance with all of the terms of its debt agreements. C) Asset Sale Bridge Credit Facility 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. D) Mandatory Debt Payments as at December 31, 2018 (1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate (“LIBOR”) based loans, prime rate loans and U.S. base rate The weighted average interest rate on outstanding debt for the year ended December 31, 2018 was 5.1 percent Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche. On October 17, 2018, the Company extended the maturity date of the $1.2 billion tranche from November 30, 2020 to November 30, 2021 and the maturity date of the $3.3 billion tranche from November 30, 2021 to November 30, 2022. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at December 31, 2018, there were no amounts drawn on Cenovus’s committed credit facility (2017 – $nil). 2019 2020 2021 2022 2023 Thereafter US$ Principal Amount 500 - - 500 450 5,324 6,774 Total C$ Equivalent 682 - - 682 614 7,263 9,241 2018 ANNUAL REPORT | 99 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 E) 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. 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 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. Net Debt to Adjusted EBITDA As at December 31, Current Portion of Long-Term Debt 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 Write-Down 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 2018 682 8,482 (781 ) 8,383 2017 - 9,513 (610 ) 8,903 2016 - 6,332 (3,720 ) 2,612 (2,669 ) 3,366 (545 ) 628 (19 ) (920 ) 2,131 2,123 (1,249 ) 854 - 50 (301 ) 795 (12 ) 1,411 725 (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 Net Debt to Adjusted EBITDA 5.9x 2.8x 1.9x NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Under the terms of Cenovus’s 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. 2018 8,383 17,468 25,851 32% 2017 8,903 19,981 28,884 31% 2016 2,612 11,590 14,202 18% Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity Net Debt to Capitalization 23. CONTINGENT PAYMENT Contingent Payment, Beginning of Year Initial Recognition on Acquisition (Note 9) Re-measurement (1) Liabilities Settled or Payable Contingent Payment, End of Year Less: Current Portion Long-Term Portion (1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings. For the year ended December 31, 2018, $124 million was payable under the contingent payment agreement (2017 – $17 million). 24. ONEROUS CONTRACT PROVISIONS Onerous Contract Provisions, Beginning of Year Liabilities Incurred Liabilities Settled Change in Assumptions Change in Discount Rate Less: Current Portion Long-Term Portion Unwinding of Discount on Onerous Contract Provisions Onerous Contract Provisions, End of Year The provision for onerous contracts relates to onerous operating leases and operating costs for office space in Calgary, Alberta. The provision represents the present value of the difference between the future lease payments that Cenovus is obligated to make under the non-cancellable lease contracts and the estimated sublease recoveries, discounted at the credit-adjusted risk-free rate of between 4.0 and 5.7 percent (2017 – 3.5 and 4.4 percent). The onerous contract provision is expected to be settled in periods up to and including the year 2040. The estimate may vary as a result of changes in the use of the leased office space and sublease arrangements, where applicable. Sensitivities on the provision: As at December 31, 2018 Credit-Adjusted Risk-Free Rate Estimated Sublease Recovery Changes to the credit-adjusted risk-free rate or the estimated sublease recoveries would have the following impact Sensitivity Range Increase Decrease ± one percent ± five percent (46 ) (40 ) 52 40 2018 206 - 50 (124 ) 132 15 117 2017 - 361 (138 ) (17 ) 206 38 168 2018 45 684 (21 ) 2 (57 ) 10 663 50 613 2017 53 8 (16 ) - - - 45 8 37 100 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 E) 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. 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 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. Net Debt to Adjusted EBITDA As at December 31, Current Portion of Long-Term Debt Long-Term Debt Less: Cash and Cash Equivalents Net Debt Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income DD&A E&E Write-Down 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 2018 682 8,482 (781 ) 8,383 2017 - 9,513 (610 ) 8,903 2016 - 6,332 (3,720 ) 2,612 (2,669 ) 3,366 (545 ) 628 (19 ) (920 ) 2,131 2,123 (1,249 ) 854 - 50 (301 ) 795 (12 ) 725 (62 ) 352 2,030 890 729 (812 ) (2,555 ) (138 ) (1,285 ) 1 (5 ) 1,411 3,236 492 (52 ) (382 ) 1,498 2 554 (198 ) - - - 6 34 1,409 Net Debt to Adjusted EBITDA 5.9x 2.8x 1.9x NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity Net Debt to Capitalization 2018 8,383 17,468 25,851 32% 2017 8,903 19,981 28,884 31% 2016 2,612 11,590 14,202 18% Under the terms of Cenovus’s 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. 23. CONTINGENT PAYMENT Contingent Payment, Beginning of Year Initial Recognition on Acquisition (Note 9) Re-measurement (1) Liabilities Settled or Payable Contingent Payment, End of Year Less: Current Portion Long-Term Portion 2018 206 - 50 (124 ) 132 15 117 2017 - 361 (138 ) (17 ) 206 38 168 (1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings. For the year ended December 31, 2018, $124 million was payable under the contingent payment agreement (2017 – $17 million). 24. ONEROUS CONTRACT PROVISIONS Onerous Contract Provisions, Beginning of Year Liabilities Incurred Liabilities Settled Change in Assumptions Change in Discount Rate Unwinding of Discount on Onerous Contract Provisions Onerous Contract Provisions, End of Year Less: Current Portion Long-Term Portion 2018 45 684 (21 ) 2 (57 ) 10 663 50 613 2017 53 8 (16 ) - - - 45 8 37 The provision for onerous contracts relates to onerous operating leases and operating costs for office space in Calgary, Alberta. The provision represents the present value of the difference between the future lease payments that Cenovus is obligated to make under the non-cancellable lease contracts and the estimated sublease recoveries, discounted at the credit-adjusted risk-free rate of between 4.0 and 5.7 percent (2017 – 3.5 and 4.4 percent). The onerous contract provision is expected to be settled in periods up to and including the year 2040. The estimate may vary as a result of changes in the use of the leased office space and sublease arrangements, where applicable. Sensitivities Changes to the credit-adjusted risk-free rate or the estimated sublease recoveries would have the following impact on the provision: As at December 31, 2018 Credit-Adjusted Risk-Free Rate Estimated Sublease Recovery Sensitivity Range ± one percent ± five percent Increase Decrease 52 40 (46 ) (40 ) 2018 ANNUAL REPORT | 101 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 25. 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: Pension Benefits OPEB 2018 2017 2018 2017 Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 9) (1) Liabilities Settled Liabilities Disposed (1) Transfers (to) from 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 2018 1,029 8 - (44 ) (30 ) 149 (136 ) (165 ) 63 1 875 2017 1,847 20 944 (70 ) (139 ) (1,621 ) (155 ) 76 128 (1 ) 1,029 (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, 2018, the undiscounted amount of estimated future cash flows required to settle the obligation is $5,163 million (2017 – $3,360 million), which has been discounted using a credit-adjusted risk-free rate of 6.5 percent (2017 – 5.3 percent) and an inflation rate of two percent (2017 – two percent). 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 $50 million to $55 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning liabilities over the estimated life of the reserves, partially offset by an increase in cost estimates. Sensitivities Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities: 2018 2017 Credit- Adjusted Risk- Inflation Credit- Adjusted Risk- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 A) Defined Benefit and OPEB Plan Obligation and Funded Status Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is: 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 Re-measurements: (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) Re-measurements: Return on Plan Assets (Excluding Interest Income) Fair Value of Plan Assets, End of Year 181 13 6 (33 ) 2 (2 ) - - - 167 141 6 2 (33 ) 4 (7 ) 113 173 14 7 (8 ) 2 (6 ) 1 - (2 ) 181 125 9 2 (8 ) 4 9 141 22 1 1 (2 ) - - - - (1 ) 21 - - - - - - - Pension and OPEB (Liability) (2) (54 ) (40 ) (21 ) (22 ) (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. The weighted average duration of the defined benefit pension and OPEB obligations are 15 years and 10 years, respectively. B) Pension and OPEB Costs For the years ended December 31, 2018 2017 2016 2018 2017 2016 Pension Benefits OPEB Defined Benefit Plan Cost Current Service Costs Past Service Costs – Curtailments Net Settlement Costs Net Interest Costs Re-measurements: Return on Plan Assets (Excluding Interest Income) (Gains) Losses from Experience Adjustments (Gains) Losses from Changes in Demographic Assumptions (Gains) Losses from Changes in Financial Assumptions Defined Benefit Plan Cost (Recovery) Defined Contribution Plan Cost Total Plan Cost 13 (2 ) - 3 7 - - - 21 22 43 14 (6 ) - 3 14 - - 4 (9 ) 1 (3 ) - - - (2 ) 1 27 28 7 22 25 47 1 - - 1 - - - (1 ) 1 - 1 2 (1 ) - 1 - - (1 ) (1 ) - - - 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. 23 2 1 (1 ) - (1 ) - (1 ) (1 ) 22 - - - - - - - (3 ) - - 1 - - - - (2 ) - (2 ) 26. OTHER LIABILITIES As at December 31, Employee Long-Term Incentives Pension and Other Post-Employment Benefit Plan (Note 27) Other 2018 41 75 42 158 27. 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. Employees who meet certain criteria may elect to 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, 2017 and the next required actuarial valuation will be as at December 31, 2020. 102 | CENOVUS ENERGY As at December 31, One Percent Increase One Percent Decrease Free Rate (138 ) 188 Rate 196 (145 ) (103 ) 2017 43 62 31 136 Free Rate Inflation Rate 197 (98 ) 192 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: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 25. DECOMMISSIONING LIABILITIES Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 9) (1) Liabilities Settled Liabilities Disposed (1) Transfers (to) from 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 2018 1,029 8 - (44 ) (30 ) 149 (136 ) (165 ) 63 1 875 2017 1,847 20 944 (70 ) (139 ) (1,621 ) (155 ) 76 128 (1 ) 1,029 (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, 2018, the undiscounted amount of estimated future cash flows required to settle the obligation is $5,163 million (2017 – $3,360 million), which has been discounted using a credit-adjusted risk-free rate of 6.5 percent (2017 – 5.3 percent) and an inflation rate of two percent (2017 – two percent). 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 $50 million to $55 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning liabilities over the estimated life of the reserves, partially offset by an increase in Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the Adjusted Risk- Inflation Adjusted Risk- 2017 Credit- 2018 Credit- Free Rate (138 ) 188 Rate 196 (145 ) Free Rate Inflation Rate (98 ) 192 197 (103 ) cost estimates. Sensitivities decommissioning liabilities: As at December 31, One Percent Increase One Percent Decrease 26. OTHER LIABILITIES As at December 31, Employee Long-Term Incentives Pension and Other Post-Employment Benefit Plan (Note 27) Other 2018 41 75 42 158 2017 43 62 31 136 27. 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. Employees who meet certain criteria may elect to 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, 2017 and the next required actuarial valuation will be as at December 31, 2020. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 A) Defined Benefit and OPEB Plan Obligation and Funded Status Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is: 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 Re-measurements: (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) Re-measurements: Return on Plan Assets (Excluding Interest Income) Fair Value of Plan Assets, End of Year Pension Benefits OPEB 2018 2017 2018 2017 181 13 6 (33 ) 2 (2 ) - - - 167 141 6 2 (33 ) 4 (7 ) 113 173 14 7 (8 ) 2 (6 ) 1 - (2 ) 181 125 9 2 (8 ) 4 9 141 22 1 1 (2 ) - - - - (1 ) 21 - - - - - - - 23 2 1 (1 ) - (1 ) - (1 ) (1 ) 22 - - - - - - - Pension and OPEB (Liability) (2) (54 ) (40 ) (21 ) (22 ) (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. The weighted average duration of the defined benefit pension and OPEB obligations are 15 years and 10 years, respectively. B) Pension and OPEB Costs For the years ended December 31, 2018 2017 2016 2018 2017 2016 Pension Benefits OPEB Defined Benefit Plan Cost Current Service Costs Past Service Costs – Curtailments Net Settlement Costs Net Interest Costs Re-measurements: Return on Plan Assets (Excluding Interest Income) (Gains) Losses from Experience Adjustments (Gains) Losses from Changes in Demographic Assumptions (Gains) Losses from Changes in Financial Assumptions Defined Benefit Plan Cost (Recovery) Defined Contribution Plan Cost Total Plan Cost 13 (2 ) - 3 7 - - - 21 22 43 14 (6 ) - 3 14 - - 4 (9 ) 1 (3 ) - - - (2 ) 1 27 28 7 22 25 47 1 - - 1 - - - (1 ) 1 - 1 2 (1 ) - 1 - - (1 ) (1 ) - - - (3 ) - - 1 - - - - (2 ) - (2 ) 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. 2018 ANNUAL REPORT | 103 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 2018 2017 70 29 12 - 2 113 89 29 11 9 3 141 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, 2017, 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, 2019 are $6 million for the defined benefit pension plan. 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, Discount Rate Future Salary Growth Rate Average Longevity (years) Health Care Cost Trend Rate Pension Benefits 2017 3.50 % 3.81 % 88.0 N/A 2018 3.50 % 3.88 % 88.2 N/A OPEB 2016 3.75 % 3.80 % 87.9 N/A 2018 3.50 % 5.08 % 88.1 6.00 % 2017 3.25 % 5.08 % 88.0 6.00 % 2016 3.75 % 5.15 % 87.9 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. 104 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Sensitivities The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is: As at December 31, One Percent Change: Discount Rate Future Salary Growth Rate Health Care Cost Trend Rate One Year Change in Assumed Life Expectancy 2018 2017 Increase Decrease Increase Decrease (25 ) 3 1 3 31 (2 ) (1 ) (3 ) (28 ) 3 1 4 36 (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 Longevity Risk Interest Rate Risk Investment Risk 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. 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 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. in debt instruments and real estate. Salary Risk 28. 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. 2018 Number of Common Shares 2017 Number of Common Shares As at December 31, Outstanding, Beginning of Year Common Shares Issued, Net of Issuance Costs and Tax Common Shares Issued to ConocoPhillips Outstanding, End of Year (thousands) Amount (thousands) Amount 1,228,790 11,040 - - - - 833,290 187,500 208,000 5,534 2,927 2,579 1,228,790 11,040 1,228,790 11,040 In connection with the Acquisition (see Note 9), 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). NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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 2018 2017 70 29 12 - 2 89 29 11 9 3 113 141 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, 2017, 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, 2019 are $6 million for the defined benefit pension plan. The OPEB is funded on an as required E) Actuarial Assumptions and Sensitivities Actuarial Assumptions basis. follows: The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as For the years ended December 31, 2018 2017 2016 2018 2017 2016 Pension Benefits OPEB Discount Rate Future Salary Growth Rate Average Longevity (years) Health Care Cost Trend Rate 3.50 % 3.88 % 88.2 N/A 3.50 % 3.81 % 88.0 N/A 3.75 % 3.80 % 87.9 N/A 3.50 % 5.08 % 88.1 6.00 % 3.25 % 5.08 % 88.0 6.00 % 3.75 % 5.15 % 87.9 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Sensitivities The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is: As at December 31, One Percent Change: Discount Rate Future Salary Growth Rate Health Care Cost Trend Rate One Year Change in Assumed Life Expectancy 2018 2017 Increase Decrease Increase Decrease (25 ) 3 1 3 31 (2 ) (1 ) (3 ) (28 ) 3 1 4 36 (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. 28. 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 Outstanding, End of Year 2018 Number of Common Shares (thousands) 1,228,790 - - 1,228,790 2017 Number of Common Shares Amount 11,040 - - 11,040 (thousands) 833,290 187,500 208,000 1,228,790 Amount 5,534 2,927 2,579 11,040 In connection with the Acquisition (see Note 9), 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). 2018 ANNUAL REPORT | 105 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. ConocoPhillips is 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, 2018, ConocoPhillips continued to hold these common shares. There were no preferred shares outstanding as at December 31, 2018 (2017 – nil). As at December 31, 2018, there were 23 million (2017 – 15 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 30A. As at December 31, 2016 Stock-Based Compensation Expense As at December 31, 2017 Stock-Based Compensation Expense As at December 31, 2018 Pre- Arrangement Earnings 4,086 - 4,086 - 4,086 Stock-Based Compensation 264 11 275 6 281 Total 4,350 11 4,361 6 4,367 29. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) As at December 31, 2016 Other Comprehensive Income (Loss), Before Tax Income Tax As at December 31, 2017 Other Comprehensive Income (Loss), Before Tax Income Tax As at December 31, 2018 Defined Benefit Pension Plan Foreign Currency Translation Adjustment Private Equity Instruments Total (13 ) 12 (3 ) (4 ) (5 ) 2 (7 ) 908 (275 ) - 633 397 - 1,030 15 (1 ) - 14 1 - 15 910 (264 ) (3 ) 643 393 2 1,038 30. 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 value 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. The NSRs vest and expire under the same terms and conditions as the underlying options. 106 | CENOVUS ENERGY The weighted average unit fair value of NSRs granted during the year ended December 31, 2018 was $2.43 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers. The following tables summarize information related to the NSRs: 1.90 % 1.66 % 28.47 % 4.50 Number of NSRs (thousands) Weighted Average Exercise Price ($) 42,727 3,950 (8,281 ) (3,912 ) 34,484 29.40 9.76 29.34 37.17 26.29 Outstanding NSRs Exercisable NSRs Weighted Average Number of Remaining NSRs Contractual (thousands) Life (years) Weighted Average Exercise Price ($) Number of NSRs (thousands) Weighted Average Exercise Price ($) 6.2 5.6 4.3 3.1 2.1 1.2 0.1 2.6 9.48 14.03 19.49 22.26 28.39 32.64 38.67 26.29 - 827 1,723 3,202 9,255 7,669 4,850 27,526 - 14.77 19.49 22.26 28.39 32.64 38.67 29.71 3,190 3,449 2,869 3,202 9,255 7,669 4,850 34,484 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 PSUs prior to 2018, 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. The number of PSUs eligible for payment on and after 2018 is based on four performance periods over three years and the units granted are multiplied by 20 percent after year one, 20 percent after year two, 20 percent after year three and 40 percent after the fourth performance period through years one to three. All PSUs are eligible to vest based on the Company achieving key pre- determined performance measures. PSUs vest after three years. The Company has recorded a liability of $32 million as at December 31, 2018 (2017 – $37 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 $nil as at December 31, 2018 and 2017. The following table summarizes the information related to the PSUs held by Cenovus employees: NSRs assumptions as follows: Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Expected Life (years) As at December 31, 2018 Outstanding, Beginning of Year Granted Forfeited Expired Outstanding, End of Year As at December 31, 2018 Range of Exercise Price ($) 5.00 to 9.99 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 B) Performance Share Units As at December 31, 2018 Outstanding, Beginning of Year Granted Cancelled Units in Lieu of Dividends Outstanding, End of Year Number of PSUs (thousands) 7,018 3,089 (4,155 ) 111 6,063 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. ConocoPhillips is 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, 2018, ConocoPhillips continued to hold these common shares. There were no preferred shares outstanding as at December 31, 2018 (2017 – nil). As at December 31, 2018, there were 23 million (2017 – 15 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 30A. As at December 31, 2016 Stock-Based Compensation Expense As at December 31, 2017 Stock-Based Compensation Expense As at December 31, 2018 Arrangement Stock-Based Earnings Compensation Pre- 4,086 - 4,086 - 4,086 264 11 275 6 281 Total 4,350 11 4,361 6 4,367 29. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) As at December 31, 2016 Other Comprehensive Income (Loss), Before Tax Income Tax As at December 31, 2017 Income Tax As at December 31, 2018 Other Comprehensive Income (Loss), Before Tax Defined Benefit Foreign Currency Translation Private Equity Pension Plan Adjustment Instruments Total (13 ) 12 (3 ) (4 ) (5 ) 2 (7 ) 908 (275 ) - 633 397 - 1,030 15 (1 ) - 14 1 - 15 910 (264 ) (3 ) 643 393 2 1,038 30. 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 value 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. The NSRs vest and expire under the same terms and conditions as the underlying options. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 NSRs The weighted average unit fair value of NSRs granted during the year ended December 31, 2018 was $2.43 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Expected Life (years) (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers. The following tables summarize information related to the NSRs: 1.90 % 1.66 % 28.47 % 4.50 Number of NSRs (thousands) 42,727 3,950 (8,281 ) (3,912 ) 34,484 Weighted Average Exercise Price ($) 29.40 9.76 29.34 37.17 26.29 Outstanding NSRs Exercisable NSRs Number of NSRs (thousands) Weighted Average Remaining Contractual Life (years) Weighted Average Exercise Price ($) Number of NSRs (thousands) Weighted Average Exercise Price ($) 3,190 3,449 2,869 3,202 9,255 7,669 4,850 34,484 6.2 5.6 4.3 3.1 2.1 1.2 0.1 2.6 9.48 14.03 19.49 22.26 28.39 32.64 38.67 26.29 - 827 1,723 3,202 9,255 7,669 4,850 27,526 - 14.77 19.49 22.26 28.39 32.64 38.67 29.71 As at December 31, 2018 Outstanding, Beginning of Year Granted Forfeited Expired Outstanding, End of Year As at December 31, 2018 Range of Exercise Price ($) 5.00 to 9.99 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 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 PSUs prior to 2018, 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. The number of PSUs eligible for payment on and after 2018 is based on four performance periods over three years and the units granted are multiplied by 20 percent after year one, 20 percent after year two, 20 percent after year three and 40 percent after the fourth performance period through years one to three. All PSUs are eligible to vest based on the Company achieving key pre- determined performance measures. PSUs vest after three years. The Company has recorded a liability of $32 million as at December 31, 2018 (2017 – $37 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, 2018 and 2017. The following table summarizes the information related to the PSUs held by Cenovus employees: As at December 31, 2018 Outstanding, Beginning of Year Granted Cancelled Units in Lieu of Dividends Outstanding, End of Year Number of PSUs (thousands) 7,018 3,089 (4,155 ) 111 6,063 2018 ANNUAL REPORT | 107 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 C) Restricted Share Units 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 generally 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 $32 million as at December 31, 2018 (2017 – $41 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, 2018 and 2017. The following table summarizes the information related to the RSUs held by Cenovus employees: As at December 31, 2018 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) 6,785 4,400 (1,777 ) (2,074 ) 127 7,461 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 $13 million as at December 31, 2018 (2017 – $17 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, 2018 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year E) Total Stock-Based Compensation For the years ended December 31, NSRs TSARs PSUs RSUs DSUs Stock-Based Compensation Expense (Recovery) Stock-Based Compensation Costs Capitalized Total Stock-Based Compensation Number of DSUs (thousands) 1,440 215 24 27 (346 ) 1,360 2016 15 (1 ) 13 13 7 47 12 59 2018 6 - (6 ) 9 - 9 4 13 2017 9 - (7 ) 3 (11 ) (6 ) 3 (3 ) 108 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 31. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, Salaries, Bonuses and Other Short-Term Employee Benefits Defined Contribution Pension Plan Defined Benefit Pension Plan and OPEB Stock-Based Compensation Expense (Note 30) Termination Benefits 32. RELATED PARTY TRANSACTIONS Key Management Compensation For the years ended December 31, Salaries, Director Fees and Short-Term Benefits Termination Benefits Post-Employment Benefits Stock-Based Compensation 2018 580 18 12 9 63 682 2017 606 19 8 (6 ) 19 646 2016 500 16 11 47 19 593 2018 34 9 3 5 51 2017 26 4 4 6 40 2016 27 - 4 4 35 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: 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. 33. FINANCIAL INSTRUMENTS Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, private equity instruments, long-term receivables, accounts payable and accrued liabilities, risk management assets and liabilities, 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. nature of these instruments. The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable 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, 2018, the carrying value of Cenovus’s debt was $9,164 million and the fair value was $8,431 million (2017 carrying value – $9,513 million; fair value – $10,061 million). Equity investments classified at FVOCI comprise equity investments in private companies. The Company classified certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. 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. There was an increase of $1 million in the fair value of the Company’s private equity instruments in the twelve months ended December 31, 2018. The following table provides a reconciliation of changes in the fair value of equity investments classified at FVOCI: As at December 31, Fair Value, Beginning of Year Net Acquisition of Investments Change in Fair Value (1) Fair Value, End of Year (1) Changes in fair value are recorded in OCI. 2018 2017 37 - 1 38 35 3 (1 ) 37 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 C) Restricted Share Units 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 generally 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 $32 million as at December 31, 2018 (2017 – $41 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, 2018 and they occur. 2017. 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 $13 million as at December 31, 2018 (2017 – $17 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, 2018 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, 2018 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year E) Total Stock-Based Compensation For the years ended December 31, NSRs TSARs PSUs RSUs DSUs Stock-Based Compensation Expense (Recovery) Stock-Based Compensation Costs Capitalized Total Stock-Based Compensation Number of RSUs (thousands) 6,785 4,400 (1,777 ) (2,074 ) 127 7,461 Number of DSUs (thousands) 1,440 215 24 27 (346 ) 1,360 2018 2017 2016 6 - (6 ) 9 - 9 4 13 9 - (7 ) 3 (11 ) (6 ) 3 (3 ) 15 (1 ) 13 13 7 47 12 59 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 31. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, Salaries, Bonuses and Other Short-Term Employee Benefits Defined Contribution Pension Plan Defined Benefit Pension Plan and OPEB Stock-Based Compensation Expense (Note 30) Termination Benefits 32. RELATED PARTY TRANSACTIONS Key Management Compensation 2018 580 18 12 9 63 682 2017 606 19 8 (6 ) 19 646 2016 500 16 11 47 19 593 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, Salaries, Director Fees and Short-Term Benefits Termination Benefits Post-Employment Benefits Stock-Based Compensation 2018 34 9 3 5 51 2017 26 4 4 6 40 2016 27 - 4 4 35 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. 33. FINANCIAL INSTRUMENTS Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, private equity instruments, long-term receivables, accounts payable and accrued liabilities, risk management assets and liabilities, 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, 2018, the carrying value of Cenovus’s debt was $9,164 million and the fair value was $8,431 million (2017 carrying value – $9,513 million; fair value – $10,061 million). Equity investments classified at FVOCI comprise equity investments in private companies. The Company classified certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. 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. There was an increase of $1 million in the fair value of the Company’s private equity instruments in the twelve months ended December 31, 2018. The following table provides a reconciliation of changes in the fair value of equity investments classified at FVOCI: As at December 31, Fair Value, Beginning of Year Net Acquisition of Investments Change in Fair Value (1) Fair Value, End of Year (1) Changes in fair value are recorded in OCI. 2018 2017 37 - 1 38 35 3 (1 ) 37 2018 ANNUAL REPORT | 109 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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, foreign exchange and interest rate swaps. Crude oil, condensate and, if entered into, 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 foreign exchange swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and 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 Foreign Exchange Interest Rate Total Fair Value 2018 Risk Management Asset Liability 156 - 7 163 2 1 - 3 Net 154 (1 ) 7 160 2017 Risk Management Liability Asset 63 - 2 65 1,031 - 20 1,051 Net (968 ) - (18 ) (986 ) 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 2018 160 2017 (986 ) 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: 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 (Amortized) Premium on Put Options Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts Fair Value of Contracts, End of Year 2018 (986 ) 1,554 (305 ) (16 ) (87 ) 160 2017 (291 ) 200 (929 ) 16 18 (986 ) (1) Includes a realized loss of $nil million (2017 – $33 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, Asset Liability Net 2018 Risk Management 2017 Risk Management Liability Asset Recognized Risk Management Positions Gross Amount Amount Offset Net Amount per Consolidated Financial Statements 277 (114 ) 117 (114 ) 160 - 135 (70 ) 1,121 (70 ) 163 3 160 65 1,051 (986 ) Net (986 ) - 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. 110 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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. There were no amounts pledged as collateral as at December 31, 2018. As at December 31, 2017, $26 million was pledged as collateral and was not able to be 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 3.9 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, 2018, the fair value of the contingent payment was estimated to be $132 million. As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is C$38.87 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to value the contingent payment was 32 percent and eight 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: Sensitivity Range Increase Decrease Canadian per U.S. Dollar Foreign Exchange Rate Option Volatility As at December 31, 2018 WCS Forward Prices WTI Option Volatility As at December 31, 2017 WCS Forward Prices WTI Option Volatility For the years ended December 31, Realized (Gain) Loss (1) Unrealized (Gain) Loss (2) Canadian per U.S. Dollar Foreign Exchange Rate Option Volatility D) Earnings Impact of (Gains) Losses From Risk Management Positions Sensitivity Range Increase Decrease ± $5.00 per bbl ± five percent ± five percent ± $5.00 per bbl ± five percent ± five percent 2018 1,554 (1,249 ) 305 (104 ) (57 ) 1 (167 ) (95 ) 2 2017 167 729 896 71 51 (12 ) 111 85 (27 ) 2016 (153 ) 554 401 (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 loss of $nil in 2018 (2017 – $33 million loss; 2016 – $58 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, 2018, Cenovus had a notional amount of US$150 million in interest rate swaps. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. As at December 31, 2018, there were US$45 million in foreign exchange contracts outstanding. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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, foreign exchange and interest rate swaps. Crude oil, condensate and, if entered into, 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 foreign exchange swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and 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 2018 Risk Management Asset Liability 156 - 7 163 2 1 - 3 Net 154 (1 ) 7 160 2017 Risk Management Asset Liability 63 1,031 - 2 - 20 65 1,051 Net (968 ) - (18 ) (986 ) The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried Level 2 – Prices Sourced From Observable Data or Market Corroboration 2018 160 2017 (986 ) As at December 31, Crude Oil Foreign Exchange Interest Rate Total Fair Value at fair value: As at December 31, liabilities: 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 (Amortized) Premium on Put Options Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts Fair Value of Contracts, End of Year 2018 (986 ) 1,554 (305 ) (16 ) (87 ) 160 2017 (291 ) 200 (929 ) 16 18 (986 ) (1) Includes a realized loss of $nil million (2017 – $33 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: 2018 Risk Management 2017 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 277 (114 ) 117 (114 ) 160 - 135 (70 ) 1,121 (70 ) (986 ) - 163 3 160 65 1,051 (986 ) 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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. There were no amounts pledged as collateral as at December 31, 2018. As at December 31, 2017, $26 million was pledged as collateral and was not able to be 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 3.9 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, 2018, the fair value of the contingent payment was estimated to be $132 million. As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is C$38.87 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to value the contingent payment was 32 percent and eight 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: 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 As at December 31, 2017 WCS Forward Prices WTI Option Volatility Canadian per U.S. Dollar Foreign Exchange Rate Option Volatility As at December 31, 2018 WCS Forward Prices WTI Option Volatility Canadian per U.S. Dollar Foreign Exchange Rate Option Volatility Sensitivity Range ± $5.00 per bbl ± five percent ± five percent Sensitivity Range ± $5.00 per bbl ± five percent ± five percent (104 ) (57 ) 1 (167 ) (95 ) 2 Increase Decrease 71 Increase Decrease 111 51 (12 ) 85 (27 ) 2016 (153 ) 554 401 D) Earnings Impact of (Gains) Losses From Risk Management Positions For the years ended December 31, Realized (Gain) Loss (1) Unrealized (Gain) Loss (2) (Gain) Loss on Risk Management From Continuing Operations 2018 1,554 (1,249 ) 305 2017 167 729 896 (1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized risk management loss of $nil in 2018 (2017 – $33 million loss; 2016 – $58 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, 2018, Cenovus had a notional amount of US$150 million in interest rate swaps. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. As at December 31, 2018, there were US$45 million in foreign exchange contracts outstanding. 2018 ANNUAL REPORT | 111 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Net Fair Value of Risk Management Positions Notional Volumes Terms Average Price 19,000 bbls/d January – December 2019 US$50.00- US$62.08/bbl As at December 31, 2018 Crude Oil Contracts WTI Collars Other Financial Positions (1) Crude Oil Fair Value Position Foreign Exchange Contracts Interest Rate Swaps Total Fair Value Fair Value Asset (Liability) 52 102 154 (1 ) 7 160 (1) Other financial positions are part of ongoing operations to market the Company’s production. In 2018, other financial positions consist of WCS and condensate futures, WTI fixed priced contracts and basis swaps. 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 and basis 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 and basis 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. Sensitivities The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent 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, 2018 Sensitivity Range Crude Oil Commodity Price ± US$5.00 per bbl Applied to WTI and Condensate Hedges Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production As at December 31, 2017 Sensitivity Range 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 Increase (78 ) 4 Decrease 80 (4 ) Increase Decrease (529 ) 11 507 (11 ) 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. 112 | CENOVUS ENERGY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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, 2018, Cenovus had US$6,774 million in U.S. dollar debt issued from Canada (2017 – US$7,650 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, $0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate $0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate 2018 339 (339 ) 2017 383 (383 ) As at December 31, 2018, the increase or decrease in net earnings for a $0.05 change in the U.S. per Canadian foreign exchange rate on the Company’s foreign exchange contracts amounts to $4 million (2017 – $nil). 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, 2018, Cenovus had a notional amount of US$150 million (2017 – US$400 million) in interest rate swaps. In the fourth quarter of 2018, the Company unwound US$250 million of interest rate swaps, resulting in a risk management gain of $23 million. 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 D) Credit Risk The Company does not have any floating rate debt as at December 31, 2018. 2018 12 (13 ) 2017 44 (50 ) 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. In 2018, the Company applied IFRS 9’s simplified approach to measuring ECL which uses a lifetime expected loss allowance for all account receivable and accrued revenue. As at December 31, 2018, approximately 90 percent of the Company’s accruals, joint operations and trade receivables were investment grade (2017 – 89 percent), and as of December 31, 2018 and 2017, substantially all of the Company’s accounts receivable were outstanding less than 60 days. The average expected credit loss on the Company’s accruals, joint operations and trade receivable were 0.4 percent as at December 31, 2018. As at December 31, 2018, Cenovus had one counterparty (2017 – 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 maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets, 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 22, 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, 2018, Cenovus had $781 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Net Fair Value of Risk Management Positions Notional Volumes Terms Average Price (Liability) 19,000 bbls/d January – December 2019 US$62.08/bbl US$50.00- Fair Value Asset 52 102 154 (1 ) 7 160 As at December 31, 2018 Crude Oil Contracts WTI Collars Other Financial Positions (1) Crude Oil Fair Value Position Foreign Exchange Contracts Interest Rate Swaps Total Fair Value A) Commodity Price Risk (1) Other financial positions are part of ongoing operations to market the Company’s production. In 2018, other financial positions consist of WCS and condensate futures, WTI fixed priced contracts and basis swaps. 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 and basis 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. 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. Sensitivities The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent 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, 2018 Sensitivity Range Increase Decrease Crude Oil Commodity Price ± US$5.00 per bbl Applied to WTI and Condensate Hedges Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production 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 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. (78 ) 4 (529 ) 11 80 (4 ) 507 (11 ) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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, 2018, Cenovus had US$6,774 million in U.S. dollar debt issued from Canada (2017 – US$7,650 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, $0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate $0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate 2018 339 (339 ) 2017 383 (383 ) As at December 31, 2018, the increase or decrease in net earnings for a $0.05 change in the U.S. per Canadian foreign exchange rate on the Company’s foreign exchange contracts amounts to $4 million (2017 – $nil). 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, 2018, Cenovus had a notional amount of US$150 million (2017 – US$400 million) in interest rate swaps. In the fourth quarter of 2018, the Company unwound US$250 million of interest rate swaps, resulting in a risk management gain of $23 million. 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 The Company does not have any floating rate debt as at December 31, 2018. 2018 12 (13 ) 2017 44 (50 ) Condensate – The Company has used fixed price and basis swaps to partially mitigate its exposure to the 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. In 2018, the Company applied IFRS 9’s simplified approach to measuring ECL which uses a lifetime expected loss allowance for all account receivable and accrued revenue. As at December 31, 2018, approximately 90 percent of the Company’s accruals, joint operations and trade receivables were investment grade (2017 – 89 percent), and as of December 31, 2018 and 2017, substantially all of the Company’s accounts receivable were outstanding less than 60 days. The average expected credit loss on the Company’s accruals, joint operations and trade receivable were 0.4 percent as at December 31, 2018. As at December 31, 2018, Cenovus had one counterparty (2017 – 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 maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets, 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 22, 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, 2018, Cenovus had $781 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. 2018 ANNUAL REPORT | 113 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Undiscounted cash outflows relating to financial liabilities are: Less than 1 As at December 31, 2018 Accounts Payable and Accrued Liabilities Risk Management Liabilities (1) Long-Term Debt (2) Contingent Payment (3) Other As at December 31, 2017 Accounts Payable and Accrued Liabilities Risk Management Liabilities (1) Long-Term Debt (2) Contingent Payment (3) Other (1) Risk management liabilities subject to master netting agreements. (2) Principal and interest, including current portion. (3) Refer to Note 33C for fair value assumptions. Year Years 2 and 3 Years 4 and 5 - - 2,138 15 1 1,833 3 1,152 15 - - - 862 113 1 Less than 1 Year Years 2 and 3 Years 4 and 5 - - 1,429 67 1 - 20 2,527 116 1 2,627 1,031 494 38 - Thereafter - - 13,256 - 2 Thereafter - - 13,309 - 2 Total 1,833 3 17,408 143 4 Total 2,627 1,051 17,759 221 4 35. SUPPLEMENTARY CASH FLOW INFORMATION For the years ended December 31, Interest Paid Interest Received Income Taxes Paid 2018 564 19 116 2017 538 31 12 2016 350 32 11 The following table provides a reconciliation of cash flows arising from financing activities: 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 Dividends Paid Non-Cash Changes: Dividends Declared Foreign Exchange (Gain) Loss Finance costs Other As at December 31, 2017 Changes From Financing Cash Flows: Dividends Paid (Repayment) of Long-Term Debt Net Issuance (Repayment) of Revolving Long-Term Debt Non-Cash Changes: Dividends Declared Current Portion of Long-Term Debt Foreign Exchange (Gain) Loss Finance Costs As at December 31, 2018 114 | CENOVUS ENERGY Dividends Payable - Current Portion of Long-Term Debt Long-Term Debt - 6,332 - - - - (225 ) 225 - - - - (245 ) - - 245 - - - - - - 892 (900 ) - - - 8 - - - - - - 682 - - 682 3,842 32 2,677 (2,700 ) - - (697 ) 28 (1 ) 9,513 - (1,144 ) (20 ) - (682 ) 817 (2 ) 8,482 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 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, 2018 Transportation and Storage (1) Operating Leases (Building Leases) (2) Capital Commitments Other Long-Term Commitments Total Payments (3) As at December 31, 2017 Transportation and Storage (1) Operating Leases (Building Leases) (2) Capital Commitments Other Long-Term Commitments Total Payments (3) 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total 1,040 1,104 1,335 1,491 1,562 16,809 23,341 104 21 148 73 2 81 78 1 45 74 - 37 77 1,425 1,831 - 32 - 147 24 490 1,313 1,260 1,459 1,602 1,671 18,381 25,686 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter Total 899 155 16 109 886 146 2 39 919 142 - 32 1,123 1,223 13,260 18,310 141 140 2,305 3,029 - 28 - 25 - 122 18 355 1,179 1,073 1,093 1,292 1,388 15,687 21,712 (1) Includes transportation commitments of $14 billion (2017 – $9 billion) that are subject to regulatory approval or have been approved, but are not yet in service. (2) Excludes committed payments for which a provision has been provided. (3) Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. Commitments for various transportation arrangements increased $5 billion from 2017 primarily due to new contracts related to the Keystone XL pipeline, expanded freight and rail terminal and tank contracts, partially offset by a decrease in operating leases due to the provision recorded for onerous leases in 2018. Terms are up to 20 years subsequent to the date of commencement. As at December 31, 2018, there were outstanding letters of credit aggregating $336 million issued as security for performance under certain contracts (2017 – $376 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 $875 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 23). 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, 2018, the estimated fair value of the contingent payment was $132 million As at December 31, 2018 Accounts Payable and Accrued Liabilities Risk Management Liabilities (1) Long-Term Debt (2) Contingent Payment (3) Other As at December 31, 2017 Accounts Payable and Accrued Liabilities Risk Management Liabilities (1) Long-Term Debt (2) Contingent Payment (3) Other 2,138 13,256 17,408 1,833 3 1,152 15 - 2,627 1,031 494 38 - - - 862 113 1 - 20 116 1 - - 15 1 - - 67 1 Less than 1 Year Years 2 and 3 Years 4 and 5 Thereafter - - - 2 - - - 2 Total 1,833 3 143 4 Total 2,627 1,051 221 4 2,527 1,429 13,309 17,759 (1) Risk management liabilities subject to master netting agreements. (2) Principal and interest, including current portion. (3) Refer to Note 33C for fair value assumptions. 35. SUPPLEMENTARY CASH FLOW INFORMATION For the years ended December 31, Interest Paid Interest Received Income Taxes Paid The following table provides a reconciliation of cash flows arising from financing activities: 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 Dividends Paid Non-Cash Changes: Dividends Declared Foreign Exchange (Gain) Loss Finance costs Other As at December 31, 2017 Changes From Financing Cash Flows: Dividends Paid (Repayment) of Long-Term Debt Non-Cash Changes: Dividends Declared Current Portion of Long-Term Debt Foreign Exchange (Gain) Loss Finance Costs As at December 31, 2018 Net Issuance (Repayment) of Revolving Long-Term Debt 2018 564 19 116 2017 538 31 12 2016 350 32 11 Dividends Payable Current Portion of Long-Term Debt Long-Term - - - - - (225 ) 225 - - - - (245 ) - - 245 - - - - - - - 892 (900 ) - - - 8 - - - - - - 682 - - Debt 6,332 3,842 32 2,677 (2,700 ) - - (697 ) 28 (1 ) 9,513 - (1,144 ) (20 ) - (682 ) 817 (2 ) 682 8,482 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 Undiscounted cash outflows relating to financial liabilities are: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 36. COMMITMENTS AND CONTINGENCIES Less than 1 Year Years 2 and 3 Years 4 and 5 Thereafter 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, 2018 Transportation and Storage (1) Operating Leases (Building Leases) (2) Capital Commitments Other Long-Term Commitments Total Payments (3) As at December 31, 2017 Transportation and Storage (1) Operating Leases (Building Leases) (2) Capital Commitments Other Long-Term Commitments Total Payments (3) 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter 1,040 104 21 148 1,313 Total 1,562 16,809 23,341 1,425 1,831 24 490 1,671 18,381 25,686 1,491 74 - 37 1,602 1,335 78 1 45 1,459 1,104 73 2 81 1,260 77 - 32 - 147 1 Year 2 Years 3 Years 4 Years 5 Years Thereafter 899 155 16 109 1,179 886 146 2 39 1,073 919 142 - 32 1,093 1,123 141 - 28 1,292 Total 1,223 13,260 18,310 3,029 140 - 25 2,305 - 122 355 1,388 15,687 21,712 18 (1) Includes transportation commitments of $14 billion (2017 – $9 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Excludes committed payments for which a provision has been provided. (2) (3) Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. Commitments for various transportation arrangements increased $5 billion from 2017 primarily due to new contracts related to the Keystone XL pipeline, expanded freight and rail terminal and tank contracts, partially offset by a decrease in operating leases due to the provision recorded for onerous leases in 2018. Terms are up to 20 years subsequent to the date of commencement. As at December 31, 2018, there were outstanding letters of credit aggregating $336 million issued as security for performance under certain contracts (2017 – $376 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 $875 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, 2018, the estimated fair value of the contingent payment was $132 million (see Note 23). 2018 ANNUAL REPORT | 115 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 37. SUBSEQUENT EVENT Subsequent to December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for cash of US$300 million. The remaining principal amounts of the Company’s unsecured notes as at January 31, 2019 are: As at January 31, 2019 5.70% due October 15, 2019 3.00% due August 15, 2022 3.80% due September 15, 2023 4.25% due April 15, 2027 5.25% due June 15, 2037 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 5.40% due June 15, 2047 US$ Principal Amount 500 500 450 1,061 666 1,400 722 300 851 6,450 116 | 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 Total Per Share - 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 ) s n o i l l i m $ ( 1,000 900 800 700 600 500 400 300 200 100 0 -100 Free Funds Flow Deficit Year Q4 Q2 Q1 Year 2018 Q3 2,992 214 3,126 (189) 286 5,857 (1) 5,856 2018 Q3 682 73 755 436 1,191 1 1,192 2018 Q3 1,259 (15) 297 977 0.80 0.79 Q3 (41) (0.03) (42) (0.03) (242) (0.20) (241) (0.20) Q3 176 80 81 15 22 59 14 271 - 271 319 (959) (640) (369) 10,026 904 11,183 (724) 545 20,844 11 20,855 Year 1,086 312 1,398 996 2,394 37 2,431 Year 2,154 (72) 552 1,674 1.36 1.36 1,380 190 3,048 (102) (29) 4,545 (2) 4,543 Q4 (178) 62 (116) 251 135 (3) 132 Q4 485 (22) 543 (36) (0.03) (0.03) Year Q4 (2,755) (1,670) (2.24) (1.36) (2,729) (1,672) (2.22) (1.36) (2,916) (1,350) (2.37) (1.10) (2,669) (1,356) (2.17) (1.10) Year 379 445 63 887 211 208 57 1,363 - 1,363 341 (1,375) (1,034) 329 Q4 169 52 89 28 18 61 28 276 - 276 15 (2) 13 289 Q2 Q1 Year Q2 Q1 Year 533 (123) 3,059 2017 7,362 555 9,852 (455) 271 17,043 1,135 18,178 2017 2,187 207 2,394 598 2,992 491 3,483 2017 (107) 252 2,914 2.64 2.64 2017 (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 2,406 259 2,232 (194) 4,610 93 17 4,627 106 99 205 (48) 157 12 169 (18) (64) (41) (0.03) (0.03) (752) (0.61) (743) (0.60) (914) (0.74) (654) (0.53) 139 164 15 318 145 53 6 522 524 2 5 (453) (448) 76 3,248 241 2,777 (239) 195 5,832 (3) 5,829 476 78 554 357 911 27 938 (17) (224) 774 0.63 0.63 (292) (0.24) (272) (0.22) (410) (0.33) (418) (0.34) 108 111 5 224 26 35 9 294 (2) 292 2 39 41 333 2018 Q2 Q1 Year 2018 2017 Q2 Q1 Year Free Funds Flow Before Dividends Operating Margin Free Funds Flow ) s n o i l l i m $ ( 700 600 500 400 300 200 100 0 -100 -200 Q4 2018 Q4 2017 Adjusted Funds Flow (2) Capital Investment Oil Sands Deep Basin Refining & Marketing Q4 2018 Q4 2017 (1) (2) (3) (4) Operating Margin is an additional subtotal found in Note 1 and Note 11 of the Annual Consolidated Financial Statements as well as Note 1 and Note 9 of the Interim 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2018 37. SUBSEQUENT EVENT Subsequent to December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for cash of US$300 million. The remaining principal amounts of the Company’s unsecured notes as at January 31, 2019 are: As at January 31, 2019 5.70% due October 15, 2019 3.00% due August 15, 2022 3.80% due September 15, 2023 4.25% due April 15, 2027 5.25% due June 15, 2037 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 5.40% due June 15, 2047 US$ Principal Amount 500 500 450 1,061 666 1,400 722 300 851 6,450 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 Total Per Share - 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 10,026 904 11,183 (724) 545 20,844 11 20,855 Year 1,086 312 1,398 996 2,394 37 2,431 Year 2,154 (72) 552 1,674 1.36 1.36 1,380 190 3,048 (102) (29) 4,545 (2) 4,543 Q4 (178) 62 (116) 251 135 (3) 132 Q4 485 (22) 543 (36) (0.03) (0.03) Year Q4 (2,755) (2.24) (2,729) (2.22) (2,916) (2.37) (2,669) (2.17) (1,670) (1.36) (1,672) (1.36) (1,350) (1.10) (1,356) (1.10) 2018 Q3 2,992 214 3,126 (189) 286 5,857 (1) 5,856 2018 Q3 682 73 755 436 1,191 1 1,192 2018 Q3 1,259 (15) 297 977 0.80 0.79 2018 Q3 (41) (0.03) (42) (0.03) (242) (0.20) (241) (0.20) Q2 Q1 3,248 241 2,777 (239) 195 5,832 (3) 5,829 2,406 259 2,232 (194) 93 4,610 17 4,627 Q2 Q1 476 78 554 357 911 27 938 106 99 205 (48) 157 12 169 Q2 Q1 2017 Year 7,362 555 9,852 (455) 271 17,043 1,135 18,178 2017 Year 2,187 207 2,394 598 2,992 491 3,483 2017 Year 533 (123) 3,059 (17) (224) 774 0.63 0.63 (18) (64) (41) (0.03) (0.03) Q2 Q1 (292) (0.24) (272) (0.22) (410) (0.33) (418) (0.34) (752) (0.61) (743) (0.60) (914) (0.74) (654) (0.53) (107) 252 2,914 2.64 2.64 2017 Year (34) (0.03) 126 0.11 2,268 2.06 3,366 3.05 Year Q4 2018 Q3 Q2 Q1 2017 Year 379 445 63 887 211 208 57 1,363 - 1,363 341 (1,375) (1,034) 329 52 89 28 169 18 61 28 276 - 276 15 (2) 13 289 80 81 15 176 22 59 14 271 - 271 319 (959) (640) (369) 108 111 5 224 26 35 9 294 (2) 292 2 39 41 333 139 164 15 318 145 53 6 522 2 524 5 (453) (448) 76 455 426 92 973 225 180 77 1,455 206 1,661 18,388 (3,210) 15,178 16,839 Free Funds Flow Before Dividends Operating Margin 1,000 ) s n o i l l i m $ ( 900 800 700 600 500 400 300 200 100 0 -100 Free Funds Flow ) s n o i l l i m $ ( 700 600 500 400 300 200 100 0 -100 -200 Free Funds Flow Deficit Q4 2018 Q4 2017 Adjusted Funds Flow (2) Capital Investment Oil Sands Deep Basin Refining & Marketing Q4 2018 Q4 2017 (1) (2) (3) (4) Operating Margin is an additional subtotal found in Note 1 and Note 11 of the Annual Consolidated Financial Statements as well as Note 1 and Note 9 of the Interim 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 $11,605 million as at May 17, 2017. 2018 ANNUAL REPORT | 117 SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics (continued) Financial Metrics (Non-GAAP Measures) Net Debt to Adjusted EBITDA (1) (2) Return on Capital Employed (3) Return on Common Equity (4) Income Tax & Exchange Rates Effective Tax Rates Using: Net Earnings From Continuing Operations Operating Earnings From Continuing Operations, Excluding Divestitures Foreign Exchange Rates (US$ per C$1) Average Period End Common Share Information Common Shares Outstanding (millions) Period End Average - Basic Average - Diluted Dividends ($ 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 Crude Oil Natural Gas Liquids (5) Total Liquids Production from Continuing Operations Natural Gas (MMcf/d) Oil Sands Deep Basin (6) Total Natural Gas Production from Continuing Operations Total Production from Continuing Operations (7) (BOE per day) Selected Average Benchmark Prices Crude Oil Prices (US$/bbl) Brent West Texas Intermediate ("WTI") Differential Brent - WTI Western Canadian Select at Hardisty ("WCS") WCS (C$) Differential WTI - WCS Mixed Sweet Blend Condensate (C5 @ Edmonton) Differential WTI - Condensate (Premium)/Discount West Texas Sour ("WTS") Differential WTI - WTS Refining Margins 3-2-1 Crack Spreads (8) (US$/bbl) Chicago Group 3 Natural Gas Prices AECO 7A Monthly Index (C$/Mcf) (9) NYMEX (US$/Mcf) Differential NYMEX - AECO (US$/Mcf) Year Q4 5.9x (8)% 5.9x (8)% (14)% (14)% Year Q4 25.7% 27.3% 2018 Q3 3.5x (1)% (4)% 2018 Q3 Q2 Q1 3.3x 0% (3)% 3.3x 12% 16% Q2 Q1 2017 Year 2.8x 16% 21% 2017 Year (2.3)% 86.9% 0.772 0.733 0.758 0.733 0.765 0.773 0.775 0.759 0.791 0.776 0.771 0.797 Year Q4 1,228.8 1,228.8 1,229.2 0.20 9.60 7.03 3,243.3 1,228.8 1,228.8 1,228.9 0.05 9.60 7.03 842.3 Year Q4 161,979 201,017 362,996 155,507 170,974 326,481 5,916 26,538 32,454 395,450 5,228 22,883 28,111 354,592 1 527 528 483,458 - 469 469 432,713 Year Q4 71.53 64.77 6.76 38.46 49.81 26.31 53.65 61.00 3.77 57.24 7.53 15.97 16.74 1.53 3.09 1.90 68.08 58.81 9.27 19.39 25.60 39.42 32.51 45.28 13.53 52.38 6.43 13.43 14.57 1.90 3.64 2.19 2018 Q3 1,228.8 1,228.8 1,229.3 0.05 12.97 10.03 657.7 2018 Q3 163,939 212,733 376,672 5,674 26,595 32,269 408,941 - 520 520 495,592 2018 Q3 75.97 69.50 6.47 47.25 61.75 22.25 62.67 66.82 2.68 55.48 14.02 19.14 18.71 1.35 2.90 1.88 Q2 Q1 1,228.8 1,228.8 1,229.3 0.05 13.65 10.38 939.3 1,228.8 1,228.8 1,228.8 0.05 10.97 8.54 804.0 Q2 Q1 171,079 218,299 389,378 6,263 27,778 34,041 423,419 157,390 202,276 359,666 6,517 28,962 35,479 395,145 1 570 571 518,530 4 549 553 487,464 Q2 Q1 74.90 67.88 7.02 48.61 62.75 19.27 62.42 68.83 (0.95) 59.64 8.24 18.36 18.04 1.03 2.80 2.00 67.18 62.87 4.31 38.59 48.79 24.28 56.98 63.04 (0.17) 61.46 1.41 12.96 15.66 1.85 3.00 1.52 2017 Year 1,228.8 1,102.5 1,102.5 0.20 11.48 9.13 2,908.3 2017 Year 124,752 167,727 292,479 3,922 16,928 20,850 313,329 10 316 326 367,635 2017 Year 54.82 50.95 3.87 38.97 50.56 11.98 48.49 51.57 (0.62) 49.91 1.04 16.77 16.61 2.43 3.11 1.26 Benchmark Prices Production from Continuing Operations 85 75 65 55 45 35 25 15 ) l b b / $ S U ( Brent WTI Condensate WCS 400,000 350,000 300,000 250,000 200,000 150,000 100,000 50,000 0 ) d / s l b b ( 2,500 2,000 1,500 1,000 500 0 ) d / f c M M ( SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties (continued) Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management) Oil Sands Foster Creek Christina Lake (1) Deep Basin Crude Oil Natural Gas Liquids Natural Gas Netbacks Year Q4 Q2 Q1 Year 2018 Q3 2017 18.0% (3.3)% 4.8% 1,117.2% 24.9% 11.4% 19.6% 4.2% 10.4% 2.3% 11.4% 2.5% 15.8% 12.3% 11.5% 3.6% 3.4% 8.3% 16.4% 6.6% (4.7)% 18.2% 7.2% 1.0% 14.3% 26.7% 6.0% 15.0% 10.8% 4.4% 19.31 17.97 18.45 18.92 21.68 19.52 2018 Q3 53.35 11.81 6.63 7.48 27.43 46.07 4.64 5.70 5.86 29.87 49.38 7.89 6.13 6.59 28.77 2018 Q3 0.95 1.85 8.89 0.03 6.73 2018 Q3 6.91 5.66 7.10 0.01 42.63 6.25 8.34 8.97 19.07 33.42 1.37 5.25 6.60 20.20 37.51 3.54 6.62 7.65 19.70 20.09 (0.35) 10.68 9.28 0.48 4.87 (1.96) 5.59 7.06 (5.82) 11.50 (1.26) 7.80 8.03 (3.07) 1.64 1.97 8.58 0.03 7.09 1.09 1.91 9.53 0.02 5.42 35.74 3.43 6.11 7.68 0.01 13.38 (0.78) 7.17 8.11 0.01 54.08 9.14 7.54 8.75 28.65 48.74 1.84 4.95 6.22 35.73 51.07 5.02 6.08 7.32 32.65 1.34 1.92 8.68 0.04 6.94 4.55 5.59 7.66 0.01 39.29 3.17 8.93 10.51 16.68 30.20 0.59 4.78 7.38 17.45 34.27 1.75 6.64 8.78 17.10 3.09 2.21 7.36 0.03 8.99 2.34 6.16 7.89 0.01 45.73 46.87 33.20 36.86 18.51 (1.13) 26.05 29.06 16.80 20.89 Year (9.90) Year 460 446 191 255 97% 470 2018 Q3 Q4 (2.40) (8.00) (16.27) (11.69) (2.35) Q2 Q1 Year Q4 460 477 197 280 2018 Q3 460 492 204 288 104% 502 107% 518 Q2 Q1 Year 460 464 203 261 101% 490 460 349 162 187 76% 369 460 442 202 240 96% 470 2017 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 2017 1.54 2.08 8.56 0.02 7.32 2017 2.07 5.43 8.46 0.01 2017 2017 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. The Oil Sands and Deep Basin netbacks are calculated on a gross basis and exclude adjustments for the natural gas that is produced by the Deep Basin segment and used as fuel by the Oil Sands segment. The consolidated netback is calculated on a net basis, after adjustments for natural gas produced by the Deep Basin segment and used as fuel by the Oil Sands segment. Oil Sands Netbacks (Excluding Realized Gain (Loss) on Risk Management) Heavy Oil - Foster Creek ($/bbl) Year Q4 Q2 Q1 Year Transportation and Blending Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Heavy Oil - Christina Lake ($/bbl) Transportation and Blending Total Heavy Oil - Oil Sands ($/bbl) Transportation and Blending Total Deep Basin (2) ($/BOE) Sales Price Royalties Operating Netback Transportation and Blending Production and Mineral Taxes Total Continuing Operations (2) ($/BOE) Sales Price Royalties Operating Netback Transportation and Blending Production and Mineral Taxes Refinery Operations (3) Crude Oil Capacity (4) (Mbbls/d) Crude Oil Runs (Mbbls/d) Heavy Oil Light/Medium Crude Utilization Refined Products (Mbbls/d) 4.7%. (2) Deep Basin Netbacks (Excluding Realized Gain (Loss) on Risk Management) Year Q4 Q2 Q1 Year Continuing Operations Netbacks (Excluding Realized Gain (Loss) on Risk Management) Year Q4 Q2 Q1 Year Realized Gain (Loss) on Risk Management - Continuing Operations Sales (2) ($/BOE) (1) In August 2018, Christina Lake achieved project payout resulting in royalties thereafter being based on an annualized calculation using the greater of either net profit or gross revenues of the project. In Q4, due to the significant widening of light-heavy oil differentials, Christina Lake incurred a negative revenue base (sales less diluent and transportation) and recorded associated royalty credits, as the annualized royalty expense through Q4 had dropped significantly versus Q3. At the same time, the widening differentials also caused the post payout royalty calculation to be based on gross revenues in Q4 versus the net profit calculation used in Q3. On an annual basis the effective rate of 4.8% is consistent with the annual gross Government posted rate of 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. Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Crude Oil NGLs Q4 2018 Q4 2017 Natural Gas (3) Represents 100% of the Wood River and Borger refinery operations. (4) Total gross crude oil capacity increased effective January 1, 2019 to 482,000 gross barrels per day. (1) (2) (3) (4) (5) (6) (7) (8) (9) 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 payment, 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. Natural gas liquids include condensate volumes. Includes production used for internal consumption by the Oil Sands segment of 310 MMcf/d and 306 MMcf/d for the three and twelve months ended December 31, 2018, respectively (2017 – no internal usage of Deep Basin production). 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. 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”). Alberta Energy Company ("AECO") natural gas monthly index. 118 | CENOVUS ENERGY SUPPLEMENTAL INFORMATION (unaudited) Operating Earnings From Continuing Operations, Excluding Divestitures 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$1) Average Period End Common Share Information Common Shares Outstanding (millions) Period End Average - Basic Average - Diluted Dividends ($ 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 Crude Oil Natural Gas Liquids (5) Natural Gas (MMcf/d) Oil Sands Deep Basin (6) Total Liquids Production from Continuing Operations Total Natural Gas Production from Continuing Operations Total Production from Continuing Operations (7) (BOE per day) Selected Average Benchmark Prices Crude Oil Prices (US$/bbl) Brent West Texas Intermediate ("WTI") Differential Brent - WTI Western Canadian Select at Hardisty ("WCS") WCS (C$) Differential WTI - WCS Mixed Sweet Blend Condensate (C5 @ Edmonton) Differential WTI - Condensate (Premium)/Discount West Texas Sour ("WTS") Differential WTI - WTS Refining Margins 3-2-1 Crack Spreads (8) (US$/bbl) Chicago Group 3 Natural Gas Prices AECO 7A Monthly Index (C$/Mcf) (9) NYMEX (US$/Mcf) Differential NYMEX - AECO (US$/Mcf) 2017 Q2 Q1 Year 3.3x 0% (3)% 3.3x 12% 16% 2.8x 16% 21% Year Q4 Q2 Q1 Year Year 5.9x (8)% Q4 5.9x (8)% (14)% (14)% 25.7% 27.3% 0.772 0.733 0.758 0.733 0.765 0.773 0.775 0.759 0.791 0.776 0.771 0.797 Year Q4 Q2 Q1 Year 1,228.8 1,228.8 1,229.2 0.20 9.60 7.03 3,243.3 1,228.8 1,228.8 1,228.9 0.05 9.60 7.03 842.3 1,228.8 1,228.8 1,229.3 0.05 13.65 10.38 939.3 1,228.8 1,228.8 1,228.8 0.05 10.97 8.54 804.0 Year Q4 Q2 Q1 Year 161,979 201,017 362,996 155,507 170,974 326,481 163,939 212,733 376,672 171,079 218,299 389,378 157,390 202,276 359,666 5,916 26,538 32,454 5,228 22,883 28,111 5,674 26,595 32,269 6,263 27,778 34,041 6,517 28,962 35,479 395,450 354,592 408,941 423,419 395,145 1 527 528 - 469 469 - 520 520 1 570 571 4 549 553 10 316 326 483,458 432,713 495,592 518,530 487,464 367,635 Year Q4 Q2 Q1 Year 71.53 64.77 6.76 38.46 49.81 26.31 53.65 61.00 3.77 57.24 7.53 15.97 16.74 1.53 3.09 1.90 68.08 58.81 9.27 19.39 25.60 39.42 32.51 45.28 13.53 52.38 6.43 13.43 14.57 1.90 3.64 2.19 74.90 67.88 7.02 48.61 62.75 19.27 62.42 68.83 (0.95) 59.64 8.24 18.36 18.04 1.03 2.80 2.00 67.18 62.87 4.31 38.59 48.79 24.28 56.98 63.04 (0.17) 61.46 1.41 12.96 15.66 1.85 3.00 1.52 2018 Q3 3.5x (1)% (4)% 2018 Q3 2018 Q3 1,228.8 1,228.8 1,229.3 0.05 12.97 10.03 657.7 2018 Q3 2018 Q3 75.97 69.50 6.47 47.25 61.75 22.25 62.67 66.82 2.68 55.48 14.02 19.14 18.71 1.35 2.90 1.88 2017 (2.3)% 86.9% 2017 1,228.8 1,102.5 1,102.5 0.20 11.48 9.13 2,908.3 2017 124,752 167,727 292,479 3,922 16,928 20,850 313,329 2017 54.82 50.95 3.87 38.97 50.56 11.98 48.49 51.57 (0.62) 49.91 1.04 16.77 16.61 2.43 3.11 1.26 2,500 2,000 1,500 1,000 ) d / f c M M ( 500 0 SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties (continued) Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management) Oil Sands Foster Creek Christina Lake (1) Deep Basin Crude Oil Natural Gas Liquids Natural Gas Year Q4 2018 Q3 Q2 Q1 2017 Year 18.0% (3.3)% 4.8% 1,117.2% 24.9% 11.4% 19.6% 4.2% 10.4% 2.3% 11.4% 2.5% 15.8% 12.3% 3.4% 11.5% 8.3% 3.6% 16.4% 6.6% (4.7)% 18.2% 7.2% 1.0% 14.3% 26.7% 6.0% 15.0% 10.8% 4.4% Netbacks 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. The Oil Sands and Deep Basin netbacks are calculated on a gross basis and exclude adjustments for the natural gas that is produced by the Deep Basin segment and used as fuel by the Oil Sands segment. The consolidated netback is calculated on a net basis, after adjustments for natural gas produced by the Deep Basin segment and used as fuel by the Oil Sands segment. Oil Sands Netbacks (Excluding Realized Gain (Loss) on Risk Management) Heavy Oil - Foster Creek ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Heavy Oil - Christina Lake ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Total Heavy Oil - Oil Sands ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Deep Basin Netbacks (Excluding Realized Gain (Loss) on Risk Management) Total Deep Basin (2) ($/BOE) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Continuing Operations Netbacks (Excluding Realized Gain (Loss) on Risk Management) Total Continuing Operations (2) ($/BOE) Sales Price Royalties Transportation and Blending Operating Production and Mineral Taxes Netback Realized Gain (Loss) on Risk Management - Continuing Operations Sales (2) ($/BOE) Refinery Operations (3) Crude Oil Capacity (4) (Mbbls/d) Crude Oil Runs (Mbbls/d) Heavy Oil Light/Medium Crude Utilization Refined Products (Mbbls/d) Year Q4 2018 Q3 Q2 Q1 2017 Year 42.63 6.25 8.34 8.97 19.07 33.42 1.37 5.25 6.60 20.20 37.51 3.54 6.62 7.65 19.70 20.09 (0.35) 10.68 9.28 0.48 4.87 (1.96) 5.59 7.06 (5.82) 11.50 (1.26) 7.80 8.03 (3.07) Year Q4 19.31 1.64 1.97 8.58 0.03 7.09 17.97 1.09 1.91 9.53 0.02 5.42 Year Q4 35.74 3.43 6.11 7.68 0.01 18.51 13.38 (0.78) 7.17 8.11 0.01 (1.13) Year (9.90) Q4 (2.40) Year 460 446 191 255 97% 470 Q4 460 477 197 280 104% 502 53.35 11.81 6.63 7.48 27.43 46.07 4.64 5.70 5.86 29.87 49.38 7.89 6.13 6.59 28.77 2018 Q3 18.45 0.95 1.85 8.89 0.03 6.73 2018 Q3 45.73 6.91 5.66 7.10 0.01 26.05 2018 Q3 (8.00) 2018 Q3 460 492 204 288 107% 518 54.08 9.14 7.54 8.75 28.65 48.74 1.84 4.95 6.22 35.73 51.07 5.02 6.08 7.32 32.65 39.29 3.17 8.93 10.51 16.68 30.20 0.59 4.78 7.38 17.45 34.27 1.75 6.64 8.78 17.10 Q2 Q1 18.92 1.34 1.92 8.68 0.04 6.94 21.68 3.09 2.21 7.36 0.03 8.99 Q2 Q1 46.87 4.55 5.59 7.66 0.01 29.06 33.20 2.34 6.16 7.89 0.01 16.80 Q2 (16.27) Q1 (11.69) Q2 Q1 460 464 203 261 101% 490 460 349 162 187 76% 369 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 2017 Year 19.52 1.54 2.08 8.56 0.02 7.32 2017 Year 36.86 2.07 5.43 8.46 0.01 20.89 2017 Year (2.35) 2017 Year 460 442 202 240 96% 470 (1) (2) In August 2018, Christina Lake achieved project payout resulting in royalties thereafter being based on an annualized calculation using the greater of either net profit or gross revenues of the project. In Q4, due to the significant widening of light-heavy oil differentials, Christina Lake incurred a negative revenue base (sales less diluent and transportation) and recorded associated royalty credits, as the annualized royalty expense through Q4 had dropped significantly versus Q3. At the same time, the widening differentials also caused the post payout royalty calculation to be based on gross revenues in Q4 versus the net profit calculation used in Q3. On an annual basis the effective rate of 4.8% is consistent with the annual gross Government posted rate of 4.7%. 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. Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Crude Oil NGLs Q4 2018 Q4 2017 Natural Gas (3) Represents 100% of the Wood River and Borger refinery operations. (4) Total gross crude oil capacity increased effective January 1, 2019 to 482,000 gross barrels per day. Benchmark Prices Production from Continuing Operations Brent WTI WCS Condensate 400,000 350,000 300,000 250,000 200,000 150,000 100,000 50,000 0 ) d / s l b b ( 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 payment, 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. Natural gas liquids include condensate volumes. usage of Deep Basin production). Includes production used for internal consumption by the Oil Sands segment of 310 MMcf/d and 306 MMcf/d for the three and twelve months ended December 31, 2018, respectively (2017 – no internal 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. 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”). Alberta Energy Company ("AECO") natural gas monthly index. 85 75 65 55 45 35 25 15 ) l b b / $ S U ( (1) (2) (3) (4) (5) (6) (7) (8) (9) 2018 ANNUAL REPORT | 119 ADVISORY Oil and Gas Information The estimates of reserves were prepared effective December 31, 2018 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 independent qualified reserves evaluators January 1, 2019 price forecasts. 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, 2018. 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 “aim”, “anticipate”, “believe”, “can be”, “capacity”, “committed”, “commitment”, “could”, “expect”, “estimate”, “focus”, “forecast”, “forward”, “future”, “guidance”, “may”, “on track”, “outlook”, “plan”, “position”, “potential”, “priority”, “projection”, “pursue”, “schedule”, “strategy”, “should”, “target”, “will”, or similar expressions and includes suggestions of future outcomes, including statements about: strategy and related milestones; schedules and plans; focus on maximizing shareholder value through cost leadership; desire to realize the best margins for our products; plans to maintain and demonstrate financial discipline while balancing growth and shareholder return; continuing to advance our operational performance and upholding our trusted reputation; expected timing for oil sands expansion phases and associated expected production capacities and capital efficiencies; projections for 2019 and future years and our plans and strategies to realize such projections; forecast exchange rates and trends; future opportunities for oil and natural gas development; forecast operating and financial results, including forecast sales prices, costs and cash flows; our commitment to continue reducing debt, including our long-term target Net Debt to Adjusted EBITDA ratio; our ability to satisfy payment obligations as they become due; priorities for and approach to capital investment decisions or capital allocation; planned capital expenditures, including the amount, timing and funding sources thereof; all statements with respect to our 2018 guidance estimates; expected future production, including the timing, stability or growth thereof; the impact of the Alberta Government’s mandatory production curtailment; our ability to take steps to partially mitigate against wider WTI and WCS price differentials; our expectation that our capital investment and any cash dividends for 2019 will be funded from internally generated cash flows and cash balance on hand; expected reserves; capacities, including for projects, transportation and refining; all statements related to government royalty regimes applicable to Cenovus, which regimes are subject to change; our ability to preserve our financial resilience and various plans and strategies with respect thereto; forecast cost reductions and sustainability thereof; our priorities, including for 2019; future impact of regulatory measures; forecast commodity prices, differentials and trends and expected impact; potential impacts of various risks, including those related to commodity prices and climate change; the potential effectiveness of our risk management strategies; new accounting standards, the timing for the adoption thereof, and anticipated impact on the Consolidated Financial Statements; the availability and repayment of our credit facilities; potential asset sales; expected impacts of the contingent payment; future use and development of technology and associated future outcomes; our ability to access and implement all technology necessary to efficiently 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 our forward-looking information is based include: forecast oil and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials and other assumptions identified in Cenovus’s 2019 guidance, available at cenovus.com; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product 120 | CENOVUS ENERGY transportation capacity; increase to our share price and market capitalization over the long-term; future narrowing of crude oil differentials; realization of expected capacity to store within our oil sands reservoirs barrels not yet produced, including that we will be able to time production and sales of our inventory at later dates when pipeline capacity has improved and crude oil differentials have narrowed; the Government of Alberta’s mandatory production curtailment will narrow the differential between WTI and WCS crude oil prices thereby positively impacting cash flows for Cenovus; the ability of our refining capacity, dynamic storage, existing pipeline commitments, financial hedge transactions and plans to ramp up crude-by-rail loading capacity to partially mitigate a portion of our WCS crude oil volumes against wider differentials; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgments; future use and development of technology and associated expected future results; 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 completion of the integration of the Deep Basin Assets; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient 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 inflation and other assumptions inherent in our current guidance set out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the contingent payment to ConocoPhillips; 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. 2019 guidance, as updated December 10, 2018, assumes: Brent prices of US$66.50/bbl, WTI prices of US$57.00/bbl; WCS of US$30.00/bbl; AECO natural gas prices of $1.75/GJ; Chicago 3-2-1 crack spread of US$16.50/bbl; and an exchange rate of $0.76 US$/C$. The risk factors and uncertainties that could cause our actual results to differ materially, include: our ability to realize the anticipated benefits of and synergies from the Acquisition; our ability 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; our ability to realize the expected impacts of our capacity to store within our oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline capacity and crude oil differentials have improved; failure of the Government of Alberta’s mandatory production curtailment to cause the differential between the WTI and the WCS crude oil prices to narrow or to narrow sufficiently to positively impact our cash flows; 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; lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; accuracy of our share price and market capitalization assumptions; 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; our ability to maintain 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; accuracy of our accounting estimates and judgments; our ability to replace and expand oil and gas reserves; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of our assets or goodwill from time to time; 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; inflationary 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 and our assumptions relating thereto; 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, 2018 ANNUAL REPORT | 121 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, 2018, available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. ABBREVIATIONS The following abbreviations have been used in this document: Crude Oil bbl Mbbls/d MMbbls BOE WTI WCS CDB MSW WTS Barrel thousand barrels per day million barrels barrel of oil equivalent West Texas Intermediate Western Canadian Select Christina Dilbit Blend Mixed Sweet Blend West Texas Sour MMBOE million barrel of oil equivalent Natural Gas Mcf MMcf Bcf GJ AECO thousand cubic feet million cubic feet billion cubic feet MMBtu million British thermal units gigajoule Alberta Energy Company NYMEX New York Mercantile Exchange 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 WTS 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 West Texas Sour 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 2018 ANNUAL REPORT | 123 NETBACK RECONCILIATIONS 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 Per Consolidated Financial Statements Adjustments Year Ended December 31, 2018 ($ millions) Oil Sands(1) Deep Basin(1) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 10,026 473 5,879 1,037 - 2,637 1,551 1,086 Continuing Operations Condensate Inventory - - - - - - - - 10,930 545 5,969 1,440 1 2,975 1,577 1,398 (4,993 ) - (4,993 ) - - - - - 904 72 90 403 1 338 26 312 Internal Usage(2) (179 ) - - (179 ) - - - - Other (69 ) - (4 ) (37 ) - (28 ) - (28 ) Year Ended December 31, 2017 ($ millions) Oil Sands(1) Deep Basin(1) Continuing Operations Condensate Inventory Internal Usage(2) 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 Per Consolidated Financial Statements Adjustments Year Ended December 31, 2016 ($ millions) Oil Sands(1) Deep Basin(1) 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 Continuing Operations Condensate Inventory - - 44 - - (44 ) - (44 ) (1,402 ) - (1,402 ) - - - - - 2,929 9 1,721 501 - 698 (179 ) 877 - - - - - - - - Internal Usage(2) - - - - - - - - Other (2 ) - - (4 ) - 2 - 2 (1) (2) Found in Note 1 of the Consolidated Financial Statements. Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment. Three Months Ended December 31, 2018 ($ 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 Deep Basin(3) Oil Sands(3) Adjustments Continuing Operations Condensate Inventory - - - - - - - - (1,026 ) - (1,026 ) - - - - - 1,570 (29 ) 1,281 348 - (30 ) 86 (116 ) 190 10 18 100 - 62 - 62 Internal Usage(4) (48 ) - - (48 ) - - - - Other (20 ) - - (9 ) - (11 ) - (11 ) 1,380 (39 ) 1,263 248 - (92 ) 86 (178 ) (3) (4) Found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment. 124 | CENOVUS ENERGY Basis of Netback Calculation Continuing Operations 5,689 545 972 1,224 1 2,947 1,577 1,370 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 476 (29 ) 255 291 - (41 ) 86 (127 ) 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 Oil Sands Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin Per Interim Consolidated Financial Oil Sands(1) Statements Deep Basin(1) Continuing Operations Condensate Inventory Internal Usage(2) Adjustments 2,424 113 1,193 271 - 847 235 612 231 2,655 (990 ) 20 24 94 1 92 - 92 133 1,217 365 1 939 235 704 - (990 ) - - - - - - - (1 ) - - 1 - 1 Basis of Netback Calculation Continuing Operations 1,650 133 228 350 1 938 235 703 Other (15 ) - 2 (15 ) - (2 ) - (2 ) - - - - - - - - (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment. Year Ended December 31, 2018 ($ millions) Foster Creek Lake Oil Natural Gas Condensate Inventory Other Adjustments Basis of Netback Calculation Christina Total Crude 2,531 2,489 5,020 371 495 532 683 450 102 391 492 868 636 473 886 1,024 2,637 1,551 1,086 1,133 1,504 1 - - 2 (1 ) - (1 ) 4,993 - 4,993 - - - - Year Ended December 31, 2017 ($ millions) Foster Creek Lake Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Christina Total Crude Adjustments Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin 1,945 2,345 4,290 178 387 465 915 131 784 52 266 403 230 653 868 1,624 2,539 176 307 1,448 2,232 8 - - 9 (1 ) - (1 ) 3,050 - 3,050 - - - - Year Ended December 31, 2016 ($ millions) Foster Creek Basis of Netback Calculation Christina Total Crude Adjustments Oil Natural Gas Condensate Inventory Other 1,509 16 1,402 Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin (3) Found in Note 1 of the Consolidated Financial Statements. 773 - 225 269 279 (90 ) 369 Lake 736 9 137 217 373 (89 ) 462 1,402 (44 ) 9 362 486 652 (179 ) 831 - 1 11 4 - 4 - - - - - Per Consolidated Financial Statements(3) Total Oil Sands 10,026 Per Consolidated Financial Statements(3) Total Oil Sands 473 5,879 1,037 2,637 1,551 1,086 7,362 230 3,704 934 2,494 307 2,187 2,929 9 1,721 501 698 (179 ) 877 Per Consolidated Financial Statements(3) Total Oil Sands 12 - - 11 1 - 1 14 - 1 57 (44 ) - (44 ) 2 - - 4 (2 ) - (2 ) - - - - - - - - - - - - - - - - - 44 - 44 December 31, 2017 ($ millions) Oil Sands(1) Deep Basin(1) Continuing Operations Condensate Inventory Internal Usage(2) Other Per Consolidated Financial Statements 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 Year Ended Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2018 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin 473 5,879 1,037 - 2,637 1,551 1,086 72 90 403 1 338 26 312 545 5,969 1,440 1 2,975 1,577 1,398 (4,993 ) - - - - - - 555 7,917 (3,050 ) 41 56 250 1 271 3,760 1,184 1 207 2,701 - 307 207 2,394 (3,050 ) - - - - - - 7,362 230 3,704 934 - 2,494 307 2,187 2,929 9 1,721 501 - 698 (179 ) 877 2,929 (1,402 ) 1,721 (1,402 ) - - - - - - - - 9 501 - 698 (179 ) 877 - - 44 - - (44 ) - (44 ) - - - - - - - - - - - - - - - - (179 ) - - - - - - - - - - - - - - - - - - - - - - December 31, 2016 ($ millions) Oil Sands(1) Deep Basin(1) Continuing Operations Condensate Inventory Internal Usage(2) Other Per Consolidated Financial Statements Adjustments - - - - - - - - - - - - (1) (2) Found in Note 1 of the Consolidated Financial Statements. Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment. Per Interim Consolidated Financial Oil Sands(3) Statements Deep Basin(3) Continuing Operations Condensate Inventory Internal Usage(4) Adjustments 1,380 (39 ) 1,263 248 - (92 ) 86 (178 ) 190 1,570 (1,026 ) 1,281 (1,026 ) 10 18 100 - 62 - 62 (29 ) 348 - (30 ) 86 (116 ) - - - - - - - - (48 ) - - (48 ) - - - - Other (20 ) - - (9 ) - (11 ) - (11 ) (3) (4) Found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment. (69 ) - (4 ) (37 ) - (28 ) - (28 ) (45 ) - (1 ) (77 ) - 33 - 33 (2 ) - - (4 ) - 2 - 2 Basis of Netback Calculation Continuing Operations 5,689 545 972 1,224 1 2,947 1,577 1,370 4,822 271 709 1,107 1 2,734 307 2,427 Basis of Netback Calculation Continuing Operations Basis of Netback Calculation Continuing Operations 1,525 9 363 497 - 656 (179 ) 835 476 (29 ) 255 291 - (41 ) 86 (127 ) Basis of Netback Calculation Continuing Operations The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our NETBACK RECONCILIATIONS Consolidated Financial Statements. Total Production From Continuing Operations Continuing Upstream Financial Results December 31, 2018 ($ millions) Oil Sands(1) Deep Basin(1) Continuing Operations Condensate Inventory Internal Usage(2) Other Per Consolidated Financial Statements Adjustments 10,026 904 10,930 (4,993 ) (179 ) 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 Per Interim Consolidated Financial Statements Deep Basin(1) Oil Sands(1) Adjustments Continuing Operations Condensate Inventory - - (1 ) - - 1 - 1 2,655 133 1,217 365 1 939 235 704 (990 ) - (990 ) - - - - - 231 20 24 94 1 92 - 92 Internal Usage(2) - - - - - - - - 2,424 113 1,193 271 - 847 235 612 Basis of Netback Calculation Continuing Operations 1,650 133 228 350 1 938 235 703 Other (15 ) - 2 (15 ) - (2 ) - (2 ) (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment. Oil Sands Year Ended December 31, 2018 ($ millions) Gross Sales Royalties Transportation and Blending Operating Netback (Gain) Loss on Risk Management Operating Margin 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 Per Consolidated Financial Statements(3) Total Oil Sands 10,026 473 5,879 1,037 2,637 1,551 1,086 Per Consolidated Financial Statements(3) Total Oil Sands Basis of Netback Calculation Total Crude Oil Christina Natural Gas Condensate Inventory Other Adjustments Foster Creek 2,531 371 495 532 1,133 683 450 Lake 2,489 102 391 492 1,504 868 636 5,020 473 886 1,024 2,637 1,551 1,086 1 - - 2 (1 ) - (1 ) 4,993 - 4,993 - - - - - - - - - - - 12 - - 11 1 - 1 Foster Creek 1,945 178 387 465 915 131 784 Basis of Netback Calculation Total Crude Oil 4,290 230 653 868 2,539 307 2,232 Christina Lake 2,345 52 266 403 1,624 176 1,448 Natural Gas Adjustments Condensate Inventory Other 8 - - 9 (1 ) - (1 ) 3,050 - 3,050 - - - - - - - - - - - 14 - 1 57 (44 ) - (44 ) 7,362 230 3,704 934 2,494 307 2,187 Basis of Netback Calculation Total Crude Christina Oil Natural Gas Adjustments Condensate Inventory Foster Creek 773 - 225 269 279 (90 ) 369 Lake 736 9 137 217 373 (89 ) 462 1,509 9 362 486 652 (179 ) 831 16 - 1 11 4 - 4 1,402 - 1,402 - - - - - - (44 ) - 44 - 44 Per Consolidated Financial Statements(3) Total Oil Other 2 - - 4 (2 ) - (2 ) Sands 2,929 9 1,721 501 698 (179 ) 877 (3) Found in Note 1 of the Consolidated Financial Statements. 2018 ANNUAL REPORT | 125 Three Months Ended December 31, 2018 ($ 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 Foster Creek 265 (5 ) 141 123 6 45 (39 ) Foster Creek 626 91 106 137 292 98 194 Lake 84 (34 ) 96 121 (99 ) 41 (140 ) Lake 804 22 96 123 563 137 426 Basis of Netback Calculation Total Crude Christina Adjustments Condensate Inventory Oil Natural Gas 349 (39 ) 237 244 (93 ) 86 (179 ) - - - 1 (1 ) - (1 ) 1,026 - 1,026 - - - - - - - - - - - Basis of Netback Calculation Total Crude Christina Oil Natural Gas Adjustments Condensate Inventory 1,430 113 202 260 855 235 620 1 - - 3 (2 ) - (2 ) 990 - 990 - - - - - - 1 - (1 ) - (1 ) Per Interim Consolidated Financial Statements(1) Total Oil Other 5 - - 3 2 - 2 Other 3 - - 8 (5 ) - (5 ) Sands 1,380 (39 ) 1,263 248 (92 ) 86 (178 ) Sands 2,424 113 1,193 271 847 235 612 Per Interim Consolidated Financial Statements(1) Total Oil Basis of Netback Calculation Adjustments Per Consolidated Financial Statements(2) (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Reflects operating margin from processing facility. The following table provides the sales volumes used to calculate Netback. Total 847 72 86 377 1 311 26 285 Other(3) Total Deep Basin Sales Volumes 57 - 4 26 - 27 - 27 904 72 90 403 1 338 26 312 Basis of Netback Calculation Adjustments Per Consolidated Financial Statements(2) Total 524 41 56 230 1 196 - 196 Other(3) Total Deep Basin 31 - - 20 - 11 - 11 555 41 56 250 1 207 - 207 (barrels per day, unless otherwise stated) Three Months Ended Year Ended December 31 December 31, December 31, 2018 2017 2018 2017 2016 143,928 186,530 330,458 143,586 193,734 337,320 162,685 204,016 366,701 121,806 161,514 69,647 79,481 283,320 149,128 - 7 1 10 17 330,458 338,524 366,905 284,984 151,961 28,111 33,147 32,454 469 509 527 106,232 117,931 120,258 20,850 316 73,492 - - - - - Less: Internal Consumption (3) (MMcf per day) (310 ) - (306 ) Sales From Continuing Operations (3) (BOE per day) 385,023 456,455 436,163 358,476 151,962 (3) Less natural gas volumes used for internal consumption by the Oil Sands segment. (1) Found in Note 1 of the interim Consolidated Financial Statements. Deep Basin Year Ended December 31, 2018 ($ millions) Gross Sales Royalties Transportation and Blending Operating Production and Mineral Taxes Netback (Gain) Loss on Risk Management Operating Margin 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 (2) (3) Found in Note 1 of the Consolidated Financial Statements. Reflects operating margin from processing facility. 126 | CENOVUS ENERGY Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(1) Other(2) Total Deep Basin Total 175 10 18 94 - 53 - 53 Total 219 20 26 87 1 85 - 85 15 - - 6 - 9 - 9 12 - (2 ) 7 - 7 - 7 190 10 18 100 - 62 - 62 231 20 24 94 1 92 - 92 Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(1) Other(2) Total Deep Basin Three Months Ended December 31, 2018 ($ millions) 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 Oil Sands Foster Creek Christina Lake Total Oil Sands Crude Oil Natural Gas (MMcf per day) Total Oil Sands (BOE per day) Deep Basin Total Liquids Natural Gas (MMcf per day) Total Deep Basin (BOE per day) Three Months Ended December 31, 2018 ($ millions) Foster Creek Lake Oil Natural Gas Condensate Inventory Other Basis of Netback Calculation Christina Total Crude Adjustments Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin 265 (5 ) 141 123 6 45 (39 ) 84 (34 ) 96 121 (99 ) 41 349 (39 ) 237 244 (93 ) 86 (140 ) (179 ) - - - 1 (1 ) - (1 ) 1,026 - 1,026 - - - - Three Months Ended December 31, 2017 ($ millions) Foster Creek Basis of Netback Calculation Christina Total Crude Adjustments Oil Natural Gas Condensate Inventory Other 626 91 106 137 292 98 194 Lake 804 22 96 123 563 137 426 1,430 113 202 260 855 235 620 1 - - 3 (2 ) - (2 ) 990 - 990 - - - - Per Interim Consolidated Financial Statements(1) Total Oil Sands 5 - - 3 2 - 2 3 - - 8 (5 ) - (5 ) 1,380 (39 ) 1,263 248 (92 ) 86 (178 ) 2,424 113 1,193 271 847 235 612 Per Interim Consolidated Financial Statements(1) Total Oil Sands - - - - - - - - - 1 - (1 ) - (1 ) (1) Found in Note 1 of the interim Consolidated Financial Statements. Three Months Ended December 31, 2018 ($ 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 Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(1) Total 175 10 18 94 - 53 - 53 Other(2) Total Deep Basin 15 - - 6 - 9 - 9 190 10 18 100 - 62 - 62 Basis of Netback Calculation Adjustments Per Interim Consolidated Financial Statements(1) Total 219 20 26 87 1 85 - 85 Other(2) Total Deep Basin 12 - (2 ) 7 - 7 - 7 231 20 24 94 1 92 - 92 Basis of Netback Calculation Adjustments Per Consolidated Financial Statements(2) (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Reflects operating margin from processing facility. The following table provides the sales volumes used to calculate Netback. Other(3) Total Deep Basin Sales Volumes (barrels per day, unless otherwise stated) Three Months Ended Year Ended December 31 December 31, 2018 December 31, 2017 2018 2017 2016 Oil Sands Foster Creek Christina Lake Total Oil Sands Crude Oil Natural Gas (MMcf per day) Total Oil Sands (BOE per day) Deep Basin Total Liquids Natural Gas (MMcf per day) Total Deep Basin (BOE per day) 143,928 186,530 330,458 143,586 193,734 337,320 162,685 204,016 366,701 121,806 161,514 69,647 79,481 283,320 149,128 - 7 1 10 17 330,458 338,524 366,905 284,984 151,961 28,111 33,147 32,454 469 509 527 106,232 117,931 120,258 20,850 316 73,492 - - - - - Less: Internal Consumption (3) (MMcf per day) (310 ) - (306 ) Sales From Continuing Operations (3) (BOE per day) 385,023 456,455 436,163 358,476 151,962 (3) Less natural gas volumes used for internal consumption by the Oil Sands segment. 2018 ANNUAL REPORT | 127 Transportation and Blending Gross Sales Royalties Operating Netback (Gain) Loss on Risk Management Operating Margin Deep Basin Year Ended December 31, 2018 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2017 ($ millions) Gross Sales Royalties Operating Netback Transportation and Blending Production and Mineral Taxes (Gain) Loss on Risk Management Operating Margin (2) (3) Found in Note 1 of the Consolidated Financial Statements. Reflects operating margin from processing facility. Total 847 72 86 377 1 311 26 285 Total 524 41 56 230 1 196 - 196 57 - 4 26 - 27 - 27 31 - - 20 - 11 - 11 904 72 90 403 1 338 26 312 555 41 56 250 1 207 - 207 Basis of Netback Calculation Adjustments Per Consolidated Financial Statements(2) Other(3) Total Deep Basin ADJUSTED FUNDS FLOW AND FREE FUNDS FLOW RECONCILIATION The following is a reconciliation of adjusted funds flow and free funds flow to the nearest GAAP measure for the second and third quarters of 2018: ($ millions) Cash from Operating Activities Deduct (Add Back) Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow Capital Investment Free Funds Flow Q3 2018 1,259 (15) 297 977 271 706 Q2 2018 533 (17) (224) 774 292 482 Total 1,792 (32) 73 1,751 563 1,188 128 | CENOVUS ENERGY ADJUSTED FUNDS FLOW AND FREE FUNDS FLOW RECONCILIATION The following is a reconciliation of adjusted funds flow and free funds flow to the nearest GAAP measure for the NOTES second and third quarters of 2018: ($ millions) Cash from Operating Activities Deduct (Add Back) Net Change in Other Assets and Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow Capital Investment Free Funds Flow Q3 2018 1,259 (15) 297 977 271 706 Q2 2018 533 (17) (224) 774 292 482 Total 1,792 (32) 73 1,751 563 1,188 2018 ANNUAL REPORT | 129 NOTES 130 | CENOVUS ENERGY NOTES 2018 ANNUAL REPORT | 131 NOTES 132 | 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 24, 2019 at 1 p.m. MT 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 www.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. If your shares are held by a broker, please contact your broker. 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 ﬁ led 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 signiﬁ cant 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 www.cenovus.com/about/governance/key-governance- documents.html, we are in compliance with the NYSE corporate governance standards in all signiﬁ cant 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 March 1, 2019) Alex Pourbaix, President & Chief Executive Ofﬁ cer Harbir Chhina, EVP & Chief Technology Ofﬁ cer Keith Chiasson, EVP, Downstream Jon McKenzie, EVP & Chief Financial Ofﬁ cer Al Reid, EVP, Stakeholder Engagement, Safety, Legal & General Counsel Kam Sandhar, SVP, Strategy & Corporate Development Sarah Walters, SVP, Corporate Services Drew Zieglgansberger, EVP, Upstream CENOVUS’S BOARD OF DIRECTORS (as at March 1, 2019) Patrick D. Daniel, Board Chair, Calgary, Alberta (7) Susan F. Dabarno, Bracebridge, Ontario (1,3,4) Alex J. Pourbaix, Calgary, Alberta (6) Harold N. Kvisle, Calgary, Alberta (1,3,5) Steven F. Leer, Boca Grande, Florida (2,3,4) Keith A. MacPhail, Calgary, Alberta (2,3,4) Richard J. Marcogliese, Alamo, California (2,5) Claude Mongeau, Montreal, Quebec (1,3,5) Charles M. Rampacek, Fredericksburg, Texas (2, 5) Colin Taylor, Toronto, Ontario (1, 4) Wayne G. Thomson, Calgary, Alberta (1,4) Rhonda I. Zygocki, Friday Harbor, Washington (2,5) (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 ofﬁ cer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board (7) Ex-ofﬁ cio non-voting member of all committees of Cenovus’s Board a d a n a C n i d e t n i r P 2018 ANNUAL REPORT | 133 Demonstrating industry-leading cost discipline Working with Aboriginal communities The phase G expansion at Cenovus’s Christina Lake oil sands project is a We work to develop mutually beneﬁ cial relationships with Aboriginal great example of our continuing focus on capital discipline. The project communities near our operations and aim to procure goods and is several months ahead of schedule and is an estimated 25% below services from local providers whenever possible. In 2018, we spent budget, largely due to advances in well pad design, longer well approximately $200 million purchasing everything from camp catering lengths and increased efﬁ ciencies in facility construction. We expect to well and earthworks services from local Aboriginal businesses. Since Christina Lake phase G will be completed with industry-leading capital becoming a standalone company in December 2009, Cenovus has efﬁ ciencies of between $15,000 and $16,000 per barrel of capacity. spent more than $2.7 billion doing business with Aboriginal companies in the areas where we operate. TABLE OF CONTENTS VISION, MISSION AND VALUES MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER MESSAGE FROM OUR BOARD CHAIR 1 2 4 5 MANAGEMENT’S DISCUSSION AND ANALYSIS 63 CONSOLIDATED FINANCIAL STATEMENTS 72 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 117 SUPPLEMENTAL INFORMATION 120 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 120. 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 E N E R G Y 2 0 1 8 A N N U A L R E P O R T c e n o v u s . c o m 500 Centre Street SE, PO Box 766, Calgary, Alberta T2P 0M5, Canada F SC F PO 2018 ANNUAL REPORT

Continue reading text version or see original annual report in PDF format above