Cenovus Energy Inc (CVE) 2019年年度報告「TSX」.pdf

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1、2019 ANNUAL REPORTTABLE OF CONTENTS1 VISION,MISSION AND VALUES2 MESSAGE FROM OUR PRESIDENT&CHIEF EXECUTIVE OFFICER4 MESSAGE FROM OUR BOARD CHAIR5 MANAGEMENTS DISCUSSION AND ANALYSIS61 CONSOLIDATED FINANCIAL STATEMENTS71 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS116 SUPPLEMENTAL INFORMATION119 ADVISO

2、RY133 INFORMATION FOR SHAREHOLDERSFor additional information about forward-looking statements,non-GAAP measures and reserves contained in this annual report,see Non-GAAP Measures and Additional Subtotals on page 5 and our Advisory on page 119.Our focus on sustainabilityAt Cenovus,sustainability is e

3、ssential to the way we do business.We believe striking the right balance among environmental,economic and social considerations creates long-term value.In 2019,we identifi ed four environmental,social and governance(ESG)focus areas that are most material to Cenovus and its stakeholders and establish

4、ed meaningful,bold ESG targets,with pathways to achieve them.Our four ESG focus areas are:climate&greenhouse gas(GHG)emissions,Indigenous engagement,land&wildlife and water stewardship.Our ESG targets are:to reduce companywide GHG emissions intensity by 30 percent*and hold absolute emissions fl at b

5、y 2030 compared with a 2019 baseline,with a long-term ambition to reach net zero emissions by 2050 to spend at least an additional$1.5 billion with Indigenous businesses from 2020 to 2030 to reclaim 1,500 decommissioned well sites and complete$40 million of caribou habitat restoration work by 2030 t

6、o achieve a maximum fresh water intensity of 0.1 barrels per barrel of oil equivalent by 2030*Includes scope 1 and 2 emissions from operated facilities.For more details,see the Defi nitions section in the Advisory of our January 9,2020 ESG targets news release,available on under News&Views.Our strat

7、egyOur 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 fl exibility to proceed with opportuniti

8、es 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 compe

9、titive advantage.To be the energy company of choice for investors,staff and stakeholders.Safety Safety before all else.Integrity We are transparent,honest and treat everyone with respect.Performance We work as one team to make smart decisions that deliver results.Accountability We do what we say we

10、will do.To maximize the value of the company by responsibly developing oil and natural gas assets in a safe,innovative and efficient way.OUR VISIONOUR VALUESOUR MISSION2019 ANNUAL REPORT|1Were a Canadian integrated oil and natural gas company Headquartered in Calgary,Cenovus operates oil sands proje

11、cts 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.T

12、he photo above shows steam generators and heat exchangers at our Christina Lake oil sands operations.2|CENOVUS ENERGYM E S S AG E F ROM OU RPRESIDENT&CHIEF EXECUTIVE OFFICERCenovuss unwavering focus on capital discipline,maintaining our low cost structure and deleveraging our balance sheet continues

13、 to pay off.In 2019,we delivered excellent operating and financial performance,and our total shareholder return for the year was among the best in our peer group.Near the end of the year,we announced a 25 percent dividend increase effective in the fourth quarter.We also made significant progress in

14、continuing to incorporate sustainability into our business strategy.Overall,2019 was a very strong year for our company.So far in 2020,our industry has faced some new challenges,including unprecedented turmoil in the equity and commodity markets in early March.While this significantly impacted our s

15、hare price and that of our peers,I believe our strong balance sheet and low cost structure have provided us with flexibility in our business plan to address the market volatility and remain financially resilient.In March,consistent with our commitment to balance sheet strength,we adjusted our planne

16、d 2020 capital spending to reduce discretionary capital while maintaining our base business and delivering safe and reliable operations.OperationsAcross our operations,we remain committed to best-in-class safety performance.In 2019,we saw an overall reduction in significant incidents and process saf

17、ety incidents compared with 2018.And while our injury rate was slightly higher in 2019 than the year before,it was still one of our best performances on record for the company.In 2020 and beyond,Cenovus will remain focused on asset integrity,managing critical risks and growing our safety culture.Our

18、 Christina Lake and Foster Creek oil sands facilities achieved a landmark business milestone in 2019,reaching one billion barrels of cumulative oil sands production using SAGD technology.Both facilities continued to run very efficiently,with leading operating and sustaining capital costs.At Christin

19、a Lake,we achieved first steam at our newly-completed phase G expansion in January 2019,though in light of the Government of Albertas mandatory production curtailment program,we delayed plans to ramp up phase G.Our crude-by-rail shipping capacity reached our target of approximately 100,000 barrels p

20、er day by the end of 2019.In response to low oil prices in 2020,we have decided to temporarily suspend our crude-by-rail program and have deferred final investment decisions on major growth projects.In 2019,we continued work to optimize our Deep Basin operating model to reduce costs,improve efficien

21、cy and maximize value.At our Marten Hills property,we launched a drilling program in the third quarter of 2019 to further assess the potential of this promising conventional heavy oil play.With the recent significant drop in global commodity prices,we have decided to defer discretionary 2020 planned

22、 capital spending in the Deep Basin and Marten Hills.Our integrated business model continues to demonstrate its value as our refining&marketing business generated$737 million in operating margin last year.And to further enhance our ability to maximize the value of every barrel of oil we ship,we bega

23、n exploring the potential to build a diluent recovery unit,or DRU,at our Bruderheim crude-by-rail terminal last year.If planned pipeline projects are delayed further,a DRU could allow us to increase our rail shipping capacity while reducing transportation costs.In 2020,modest spending on engineering

24、 and permitting for a potential DRU will be completed,however,Cenovus does not intend to sanction any new projects in a low commodity price environment.Financial performanceTogether,our top-tier asset base and low cost structure give Cenovus a competitive advantage.In 2019,even with our production c

25、urtailed,we generated more than$2.5 billion in free funds flow.That gave us flexibility to continue deleveraging our balance sheet.We reduced net debt to about$6.5 billion at the end of the year,down from approximately$8.4 billion at the end of 2018,and we remain focused on further deleveraging towa

26、rds our long-term net debt target of$5 billion.We ended the year with approximately$4.4 billion in liquidity,including undrawn credit facility capacity and cash on hand.2019 ANNUAL REPORT|32019 TOTAL SHAREHOLDER RETURNThis chart shows cumulative shareholder return for every$100 invested(assuming qua

27、rterly reinvestment of dividends)over the period December 31,2018 to December 31,2019.120150Cenovus Energy(TSX)S&P TSX Composite IndexS&P TSX Energy Index$150$140$130$120$110$100$90December 31,2018March 31,2019June 30,2019September 30,2019December 31,2019In October,we outlined a new five-year busine

28、ss plan that allowed for disciplined production growth,subject to improved market access.That plan outlined the potential for approximately$11 billion in cumulative free funds flow through 2024,using mid-cycle commodity prices.In response to the significant drop in oil prices this year,we are review

29、ing the companys forecasts and business plan and will adjust accordingly.SustainabilityFor as long as our company has been around,Cenovus has been focused on sustainably producing Canadas oil and natural gas resources.We believe striking the right balance among environmental,economic and social cons

30、iderations creates long-term value.In 2019,we made considerable progress in continuing to incorporate sustainability into our business strategy.We established a Sustainability Advisory Council of senior leaders from key areas of our business to advise on sustainability initiatives for the company.We

31、 conducted a materiality assessment to identify the environmental,social and governance,or ESG,focus areas that are most impactful to our business climate&greenhouse gas emissions,Indigenous engagement,land&wildlife and water stewardship.And we worked with global experts,through a rigorous process,t

32、o establish bold targets for those focus areas.Our ESG targets include reducing our GHG emissions intensity by another 30 percent over the next 10 years while holding absolute emissions at 2019 levels.We also have a long-term ambition to achieve net zero emissions by 2050.These are among the boldest

33、 emissions targets and ambitions in the world for an upstream exploration and production company.These and other sustainability efforts were undertaking are aligned with the priorities in our five-year business plan.Were committing to them because its the right thing to do and because our investors

34、are increasingly demanding equally strong financial,operating and ESG performance.By taking these steps,were positioning Cenovus for long-term business resilience.These are just a few of our successes in 2019.Im extremely proud of our team and of the progress we have made since I joined Cenovus two

35、and half years ago.Clearly,we face significant challenges in the coming year,however,Im confident we have the financial flexibility,the talent and the ingenuity to help us navigate through this tumultuous period.In closing,I would like to extend my thanks and best wishes to Pat Daniel for his long s

36、ervice as Chair of our Board and as a Director.Pat will not be standing for re-election to the Board this year./s/Alex Pourbaix President&Chief Executive Officer4|CENOVUS ENERGYM ESSAGE FROM OURBOARD CHAIRIn 2019,Cenovus demonstrated excellent operating and financial performance and further strength

37、ened its position as an industry leader in sustainable oil and natural gas development.Management continued to deliver on its commitments to shareholders,maintaining Cenovuss low cost structure,exercising capital discipline,further reducing debt and delivering strong free funds flow.This contributed

38、 to a nearly 38 percent increase in our share price from the end of 2018,which was leading performance within our oil sands industry peer group.Unfortunately,the significant market turmoil that impacted benchmark crude oil prices in March had a dramatic impact on share valuations across our industry

39、.Your management team has acted swiftly and decisively in charting a course to help the company through this challenging period and protect all of the hard work weve done over the last few years to strengthen Cenovus and keep it well-positioned for future success.Cenovuss strategy and new five-year

40、business plan were well received at our Investor Day last October.In 2019,as in previous years,I and other Board members engaged in outreach efforts with several of our companys largest shareholders.We received valuable feedback on a variety of topics including Cenovuss performance,strategy,executiv

41、e compensation,board renewal and governance practices.While investors at that time were concerned about market access and other macro-economic factors affecting our industry,we continue to hear strong support for the direction the company is taking and for Cenovuss industry leadership under Alex as

42、President&Chief Executive Officer.The Board will continue its investor outreach efforts in 2020 as we navigate through this current low commodity price environment.The Board renewal process continued in 2019 with the election of Jane Kinney as a director in April and the addition of George Lewis as

43、a director in July.I would like to welcome Keith Casey,who will stand as a director nominee at this years Annual Meeting of Shareholders.Mr.Casey is the Chief Executive Officer at Tatanka Midstream LLC and has worked in the refining industry since 1998.Wayne Thomson and I will not be standing for re

44、-election in 2020.I would like to thank Mr.Thomson for his guidance and counsel since the inception of Cenovus.In February of this year,the Board revised Cenovuss Board Diversity Policy to reflect the companys commitment to the principles of diversity.The policy now includes a 2025 aspirational targ

45、et to have at least 40 percent of independent members be represented by women,Aboriginal peoples,persons with disabilities and members of visible minorities,with at least three women as independent members of the Board.While diversity is an important and valuable consideration in assessing potential

46、 candidates for the Board,all nominations and appointments are made on merit in the context of the skills,expertise and experience that Cenovus requires.To enhance their skills and strengthen their understanding of our business environment,we provide continuing education opportunities for all direct

47、ors.In 2019,this included a market risk management and hedging workshop,information technology strategy workshop and cybersecurity workshop presented by Cenovus staff.In closing,2019 was another excellent year for Cenovus.There are some challenges ahead,but we have a solid strategy and best-in-class

48、 assets.Shareholders should have confidence in the strategic direction of the company and in the Boards ability to provide strong and sound guidance and oversight in the year ahead and beyond./s/Patrick Daniel Board Chair2019 ANNUAL REPORT|5MANAGEMENTS DISCUSSION AND ANALYSISFOR THE YEAR ENDED DECEM

49、BER 31,20196 OVERVIEW OF CENOVUS6 YEAR IN REVIEW8 OPERATING AND FINANCIAL RESULTS13 COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS16 REPORTABLE SEGMENTS 17 OIL SANDS 21 DEEP BASIN 24 REFINING AND MARKETING 25 CORPORATE AND ELIMINATIONSThis Managements Discussion and Analysis(“MD&A”)for Cenovus En

50、ergy Inc.(which includes references to“we”,“our”,“us”,“its”,the“Company”,or“Cenovus”,and means Cenovus Energy Inc.,the subsidiaries of,and partnership interests held by,Cenovus Energy Inc.and its subsidiaries)dated February 11,2020,should be read in conjunction with our December 31,2019 audited Cons

51、olidated Financial Statements and accompanying notes(“Consolidated Financial Statements”).All of the information and statements contained in this MD&A are made as of February 11,2020,unless otherwise indicated.This MD&A contains forward-looking information about our current expectations,estimates,pr

52、ojections 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(“Management”)prepared the MD&A.The Audit Committee of the Cenovus Board of Directors(t

53、he“Board”)reviewed and recommended the MD&A for approval by the Board,which occurred on February 11,2020.Additional information about Cenovus,including our quarterly and annual reports,the Annual Information Form(“AIF”)and Form 40-F,is available on SEDAR at ,on EDGAR at sec.gov,and on our website at

54、 .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,(which includes references to“dollar”or“$”)

55、,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.We adopted IFRS 16,“Leases”(“IFRS 16”),ef

56、fective January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section of this MD&A for further information.Non-GAAP Measures and Additional Subtotals

57、 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,Net Debt,Capitalization and Adjusted Earnings Before Interest,Taxes,Depreciation and Amortization(“Adjusted EBITDA”)and theref

58、ore 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

59、 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

60、in accordance with IFRS.The definition and reconciliation,if applicable,of each non-GAAP measure or additional subtotal is presented in the Operating and Financial Results,Liquidity and Capital Resources sections of this MD&A as well as the Netback Reconciliations on page 123.28 DISCONTINUED OPERATI

61、ONS29 QUARTERLY RESULTS31 OIL AND GAS RESERVES32 LIQUIDITY AND CAPITAL RESOURCES35 RISK MANAGEMENT AND RISK FACTORS52 CRITICAL ACCOUNTING JUDGMENTS,ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES56 CONTROL ENVIRONMENT56 SUSTAINABILITY56 OUTLOOK6|CENOVUS ENERGYOVERVIEW OF CENOVUS We are a Canadian i

62、ntegrated oil and natural gas company headquartered in Calgary,Alberta,with our shares listed on the Toronto and New York stock exchanges.On December 31,2019,we had an enterprise value of approximately$24 billion.Operations include oil sands projects in northeast Alberta and established crude oil,na

63、tural gas liquids(“NGLs”)and natural gas production in Alberta and British Columbia.Total production from our upstream assets averaged approximately 452,000 BOE per day in 2019.We also conduct marketing activities and have ownership interest in refining operations in the United States(“U.S.”).The re

64、fineries processed an average of 443,000 gross barrels per day of crude oil feedstock into an average of 466,000 gross barrels per day of refined products in 2019.Our Strategy Our strategy is focused on maximizing shareholder value through cost leadership and realizing the best margins for our produ

65、cts.Our business plan through 2024 will focus on sustainably growing shareholder returns and further reducing Net Debt as well as continuing to integrate Environmental,Social and Governance(“ESG”)considerations into our business plan.We believe that maintaining a strong balance sheet will help Cenov

66、us 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 inv

67、estment grade status.Our investment focus will be on areas where we believe we have the greatest competitive advantage.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 recor

68、d of strong operational performance while demonstrating technical leadership to improve reserves,production and earnings.We are focused on advancing innovation to unlock future opportunities that maximize value from our vast resource base and improve our environmental footprint.Conventional Oil and

69、Natural Gas We are committed to 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&Refini

70、ng We 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 engagin

71、g 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.For a description of our operations,refe

72、r to the Reportable Segments section of this MD&A.YEAR IN REVIEW In 2019,we delivered on the commitments we made to our shareholders,as we:Progressed our deleveraging plans by repaying US$1.8 billion of our unsecured notes and reducing Net Debt to$6.5 billion;Improved our long-term market access pos

73、ition through incremental pipeline capacity,strategic rail agreements and securing additional storage in the U.S.Gulf Coast(“USGC”)to support the ramp up of our crude-by-rail activity;Ramped up our crude-by-rail activity by loading 53,345 barrels per day for delivery to U.S.destinations.Of these vol

74、umes,we sold an average of 48,626 barrels per day.We exited the year with our December loaded volumes averaging 105,985 barrels per day and rail sales of 91,059 barrels per day;020,00040,00060,00080,000100,000120,000Q4 2018Q1 2019Q2 2019Q3 2019Q4 2019(barrels per day)Crude-by-Rail Volumes to U.S.Des

75、tinationsTotal Rail Volumes Loaded to U.S.DestinationsCenovus Rail Sales at U.S.Destinations2019 ANNUAL REPORT|7Invested$1,176 million of capital compared with$1,363 million in 2018,reflecting our continued focus on capital discipline;Focused on cost leadership reflected in our operating cost reduct

76、ions in our upstream assets;Increased our fourth quarter dividend 25 percent to$0.0625 per share;and Achieved production of one billion barrels of oil using steam-assisted gravity drainage(“SAGD”)technology.Upstream operational performance was very good,with production averaging 451,680 BOE per day,

77、limited by the Government of Albertas industry-wide mandatory production curtailment program.Our refineries demonstrated good performance despite unplanned outages throughout the year,and the turnaround activities at both the Wood River and Borger refineries(the“Refineries”)in the fourth quarter.Eff

78、ective January 1,2020,as a result of new maximum demonstrated rates in 2019,Wood River was re-rated to reflect higher crude oil processing capacity of 346,000 gross barrels per day(2019 333,000 gross barrels per day).Crude oil prices continued to be volatile throughout the year.West Texas Intermedia

79、te(“WTI”)benchmark crude price ranged from a high of US$66.30 per barrel to a low of US$46.54 per barrel and averaged 12 percent lower than in 2018.The differential between WTI and Western Canadian Select(“WCS”)at Hardisty prices narrowed to an average of US$12.76 per barrel,a 52 percent decrease co

80、mpared with 2018,supported by the Government of Albertas mandatory production curtailment program.The increase in the benchmark WCS prices to US$44.27 per barrel(2018 US$38.46 per barrel)and a decrease in the cost of condensate used for blending had a positive impact on our upstream financial result

81、s(operating margin).With market access constraints for Canadian crude oil production continuing,we have progressed on our strategy to maintain firm transportation through a combination of pipelines,rail and marine access.In 2019,we acquired additional pipeline and rail storage capacity allowing us t

82、o transport over 25 percent of our Oil Sands production to be sold at U.S.destinations which contributed to our increased realized price.We exited the year with 187,645 barrels per day of our Oil Sands production sold at U.S.destinations.We achieved upstream operating margin from continuing operatio

83、ns of$3,723 million compared with$1,398 million in 2018,due to an increase in our average realized crude oil sales price and realized risk management losses of$23 million compared with$1,577 million in 2018.Our Refining and Marketing segment generated operating margin of$737 million,down from 2018.W

84、hile market crack spreads were relatively unchanged year-over-year,realized crack spreads were down due to the narrowing medium sour and heavy crude oil differentials,which resulted in lower crude advantage,partially offset by higher margins on fixed priced products associated with a lower benchmark

85、 WTI,and a reduction in the cost of Renewable Identification Numbers(“RINs”).In 2019,we:Increased our average realized crude oil sales price to$53.95 per barrel from$37.97 per barrel in 2018;Achieved Cash from Operating Activities of$3,285 million(2018$2,154 million),Adjusted Funds Flow of$3,724 mil

86、lion(2018$1,674 million),and Free Funds Flow of$2,548 million(2018$311 million);and Recorded Net Earnings from continuing operations of$2,194 million compared with a Net Loss from continuing operations of$2,916 million in 2018.In the fourth quarter of 2019,the Government of Alberta announced a Speci

87、al Production Allowance(“SPA”)to provide curtailment relief equivalent to incremental increases in rail shipment and no curtailments on new conventional oil wells drilled to encourage more capital investment.Our production levels in 2020 are anticipated to be higher than in 2019 due to the SPA.8|CEN

88、OVUS ENERGYOPERATING AND FINANCIAL RESULTS Selected Operating Results 2019 Percent Change 2018 Percent Change 2017 Upstream Production Volumes Oil Sands(barrels per day)Foster Creek 159,598 (1)161,979 30 124,752 Christina Lake 194,659 (3)201,017 20 167,727 354,257 (2)362,996 24 292,479 Deep Basin(BO

89、E per day)97,423 (19)120,258 64 73,492 Total Production from Continuing Operations(1)(BOE per day)451,680 (7)483,458 32 367,635 Production From Discontinued Operations(Conventional)(BOE per day)-(100)294 (100)102,855 Sales from Continuing Operations(2)(BOE per day)390,813 (10)436,163 22 358,476 Oil

90、and Gas Reserves(MMBOE)Proved 5,103 (1)5,167 (1)5,232 Probable 1,768 (3)1,821 (5)1,910 Proved plus Probable 6,871 (2)6,988 (2)7,142 Refining and Marketing Crude Oil Runs(3)(Mbbls/d)443 (1)446 1 442 Refined Product(3)(Mbbls/d)466 (1)470 -470 Crude Utilization(3)(percent)92 (5)97 1 96 Crude-by-Rail(ba

91、rrels per day)Crude-by-Rail Loads(4)53,345 1,197 4,113 -Crude-by-Rail Sales(5)48,626 1,367 3,314 -(1)Includes natural gas volumes used for internal consumption by the Oil Sands segment of 320 MMcf per day for the year ended December 31,2019(306 MMcf per day in 2018 and no internal usage of Deep Basi

92、n production in 2017).(2)Excludes natural gas volumes used for internal consumption by the Oil Sands segment of 320 MMcf per day for the year ended December 31,2019(306 MMcf per day in 2018 and no internal usage of Deep Basin production in 2017).(3)Represents 100 percent of the Wood River and Borger

93、 refinery operations.Cenovuss interest is 50 percent.(4)Represents volumes transported outside of Alberta.(5)Represents volumes sold outside of Alberta.Upstream Production Volumes Our upstream operations performed very well in 2019.Oil Sands production was 354,257 barrels per day(2018 362,996 barrel

94、s per day)due to mandatory production curtailments set by the Government of Alberta.Deep Basin production in 2019 decreased to 97,423 BOE per day compared with 120,258 BOE per day in 2018 due to natural declines from lower sustaining capital investment,the divestiture of Cenovus Pipestone Partnershi

95、p(“CPP”)on September 6,2018,and temporary well shut-ins resulting from low natural gas prices.Oil and Gas Reserves Based on our reserves reports prepared by independent qualified reserves evaluators(“IQREs”),at the end of 2019 we had total proved reserves and total proved plus probable reserves of a

96、pproximately 5.1 billion BOE and 6.9 billion BOE,respectively,decreases of one percent and two percent compared with 2018.Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.Refining and Marketing Crude oil runs and refined product output in 2019 we

97、re consistent with 2018.Operational performance was impacted by planned maintenance,unplanned outages,including a fire in a crude unit at Wood River,and planned turnaround activities at the Refineries.In the first quarter of 2018,both Refineries completed major planned turnarounds.Further informatio

98、n on the changes in our financial and operating 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 Statemen

99、ts.2019 ANNUAL REPORT|9Selected Consolidated Financial Results($millions,except per share amounts)2019 Percent Change 2018(1)Percent Change 2017(1)Operating Margin from Continuing Operations(2)4,460 86 2,394 (20)2,992 Cash From Operating Activities From Continuing Operations 3,285 55 2,118 (19)2,611

100、 Total 3,285 53 2,154 (30)3,059 Adjusted Funds Flow(3)3,724 122 1,674 (43)2,914 Operating Earnings(loss)from Continuing Operations(3)456 117 (2,755)(8,003)(34)Per Share($)(4)0.37 117 (2.24)(7,367)(0.03)Net Earnings(Loss)From Continuing Operations 2,194 175 (2,916)(229)2,268 Per Share($)(4)1.78 175 (

101、2.37)(215)2.06 Total 2,194 182 (2,669)(179)3,366 Per Share($)(4)1.78 182 (2.17)(171)3.05 Total Assets 35,713 2 35,174 (14)40,933 Total Long-Term Financial Liabilities(5)8,483 (1)8,602 (11)9,717 Capital Investment(6)1,176 (14)1,363 (18)1,661 Dividends Cash Dividends 260 6 245 9 225 Per Share($)0.2125

102、 6 0.2000 -0.2000 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.(2)Additional subtotal found in N

103、otes 1 and 11 of the Consolidated Financial Statements and defined in this MD&A.(3)Non-GAAP measure defined in this MD&A.(4)Represented on a basic and diluted per share basis.(5)Includes Long-Term Debt,Lease Liabilities,Risk Management,Contingent Payment Liabilities and other financial liabilities i

104、ncluded within Other Liabilities on the Consolidated Balance Sheets.(6)Includes expenditures on property,plant and equipment(“PP&E”),Exploration and Evaluation(“E&E”)assets and assets held for sale.Operating Margin Operating Margin is an additional subtotal found in Notes 1 and 11 of the Consolidate

105、d 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,

106、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)2019 2018(1)2017(1)Gross Sales 22,042 22,113 17,769 Less:Royalties 1,172 545 271 Re

107、venues 20,870 21,568 17,498 Expenses Purchased Product 8,844 9,261 8,476 Transportation and Blending 5,234 5,969 3,760 Operating Expenses 2,324 2,367 1,956 Production and Mineral Taxes 1 1 1 Realized(Gain)Loss on Risk Management Activities 7 1,576 313 Operating Margin From Continuing Operations 4,46

108、0 2,394 2,992 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.10|CENOVUS ENERGYOperating Margin Fro

109、m Continuing Operations Variance(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.Operating Margin from continuing operations incr

110、eased in 2019 compared with 2018 primarily due to:A higher average crude oil sales price resulting from narrower differentials and an increase in our sales volumes at U.S.locations;A decrease in transportation and blending expenses due to lower condensate prices and a reduction in condensate volumes

111、 required for blending,partially offset by increased rail transportation costs and pipeline tariffs due to higher volumes shipped to the U.S.;Lower upstream operating expenses;and Lower upstream realized risk management losses of$23 million(2018 losses of$1,577 million).These increases in Operating

112、Margin were partially offset by:Higher royalties primarily due to Christina Lake achieving payout in August 2018 and higher realized prices;Lower sales volumes;and Lower Operating Margin from our Refining and Marketing segment primarily due to reduced realized crack spreads as a result of lower crud

113、e advantage.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

114、 to assist in measuring a companys 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 c

115、omposed of accounts receivable,inventories,income tax receivable,accounts payable and income tax payable.Net change in other assets and liabilities is composed of site restoration costs and pension funding.($millions)2019 2018(1)(2)2017(1)(2)Cash From Operating Activities 3,285 2,154 3,059 (Add)Dedu

116、ct:Net Change in Other Assets and Liabilities (84)(72)(107)Net Change in Non-Cash Working Capital (355)552 252 Adjusted Funds Flow 3,724 1,674 2,914 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Cr

117、itical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.(2)Includes results from our Conventional segment,which has been classified as a discontinued operation.Cash From Operating Activities and Adjusted Funds Flow were higher in 2019 compared with 2018 due

118、to higher Operating Margin,lower general and administrative costs from a reduction in rent expense primarily due to the adoption of IFRS 16 and$60 million of severance costs incurred in 2018,and lower finance costs as a result of debt repayments,partially offset by a current income tax expense of$17

119、 million compared with a recovery of$126 million in 2018.The change in non-cash working capital in 2019 was primarily due to an increase in accounts receivable and inventory,partially offset by an increase in accounts payable and a decrease in income tax receivable.In 2018,the change in non-cash wor

120、king capital was primarily due to a decrease in accounts receivable and inventory,partially offset by a decrease in accounts payable.2019 ANNUAL REPORT|11Operating Earnings(Loss)($millions)2019 2018(1)2017(1)Earnings(Loss)From Continuing Operations,Before Income Tax 1,397 (3,926)2,216 Add(Deduct):Un

121、realized Risk Management(Gain)Loss(2)149 (1,249)729 Non-Operating Unrealized Foreign Exchange(Gain)Loss(3)(787)593 (651)Revaluation(Gain)-(2,555)(Gain)Loss on Divestiture of Assets (2)795 1 Operating Earnings(Loss)From Continuing Operations,Before Income Tax 757 (3,787)(260)Income Tax Expense(Recove

122、ry)301 (1,032)(226)Operating Earnings(Loss)From Continuing Operations 456 (2,755)(34)(1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Account

123、ing Policies section in this MD&A.(2)Includes the reversal of unrealized(gains)losses recorded in prior periods.(3)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 trans

124、actions.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 discont

125、inuance,revaluation gain,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 o

126、f 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 2019,Operating Earnings from continuing operations increased compared with 2018 primarily due to:Higher Cash From Oper

127、ating Activities and Adjusted Funds Flow,as discussed above;A lower exploration expense of$82 million compared with$2,123 million;A deferred tax recovery related to the write-down of Deep Basin E&E assets in 2018;and The 2018 provision of$629 million recognized for onerous contracts.The increase in

128、our Operating Earnings in 2019 was partially offset by realized foreign exchange losses of$401 million on the repurchase of our unsecured notes compared with losses of$214 million in 2018,higher depreciation,depletion,and amortization(“DD&A”)primarily due to our right-of-use(“ROU”)assets and a loss

129、on the re-measurement of the contingent payment of$164 million(2018$50 million).Net Earnings(Loss)($millions)2019 vs.2018 2018 vs.2017 Net Earnings(Loss)From Continuing Operations,Comparative Year(1)(2,916)2,268 Increase(Decrease)due to:Operating Margin From Continuing Operations 2,066 (598)Corporat

130、e and Eliminations:Unrealized Risk Management Gain(Loss)(1,398)1,978 Unrealized Foreign Exchange Gain(Loss)1,476 (1,506)Revaluation(Gain)-(2,555)Re-measurement of Contingent Payment (114)(188)Gain(Loss)on Divestiture of Assets 797 (794)Expenses(2)573 (951)DD&A (118)(293)Exploration Expense 2,041 (1,

131、235)Income Tax Recovery(Expense)(213)958 Net Earnings(Loss)From Continuing Operations,End of Year 2,194 (2,916)(1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation

132、 Uncertainties and Accounting Policies section in this MD&A.(2)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(

133、income)loss,net and Corporate and Eliminations revenues,purchased product,transportation and blending,and operating expenses.In 2019,Net Earnings of$2,194 million from continuing operations increased from 2018 due to higher Operating Earnings,as discussed above,non-operating foreign exchange gains o

134、f$787 million compared with losses of$593 million in 2018,and the loss on the CPP divestiture in 2018.In 2019,we recorded a deferred income tax recovery of$671 million associated with the reduction in the Alberta corporate tax rate and a recovery of$387 million due to an internal restructuring of ou

135、r U.S.operations resulting in a step-up in the tax basis of our 12|CENOVUS ENERGYrefining assets.In 2018,our deferred tax recovery was$884 million related to current period losses,including the write-down of Deep Basin E&E assets,and$78 million arising from an adjustment to the tax basis of our refi

136、ning assets.These increases to our Net Earnings were partially offset by unrealized risk management losses of$149 million compared with gains of$1,249 million in 2018.Net Earnings from discontinued operations for the year ended December 31,2018 was$247 million and includes an after-tax gain of$220 m

137、illion on the divestiture of the Suffield assets in the first quarter of 2018.The Net Earnings(Loss)in 2018 decreased compared with 2017 primarily due to lower Operating Earnings,an after-tax revaluation gain of$1.9 billion on our pre-existing interest in the FCCL Partnership(“FCCL”)recognized in 20

138、17,non-operating foreign exchange losses compared with gains in 2017,and a loss on the divestiture of CPP,partially offset by unrealized risk management gains compared with losses,and a larger income tax recovery.Capital Investment($millions)2019 2018(1)2017(1)Oil Sands 706 887 973 Deep Basin 53 211

139、 225 Refining and Marketing 280 208 180 Corporate and Eliminations 137 57 77 Conventional(Discontinued Operations)-206 Capital Investment(2)1,176 1,363 1,661 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer

140、to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section of this MD&A.(2)Includes expenditures on PP&E,E&E assets and assets held for sale.Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.2019 ANNUA

141、L REPORT|13COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS Selected Benchmark Prices and Exchange Rates(1)Key performance drivers for our financial results include commodity prices,quality and location price differentials,refining crack spreads as well as the U.S./Canadian dollar exchange rate.The

142、 following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.(US$/bbl,unless otherwise indicated)Q4 2019 Q4 2018 2019 Percent Change 2018 2017 Brent Average 62.50 68.08 64.18 (10)71.53 54.82 WTI Average 5

143、6.96 58.81 57.03 (12)64.77 50.95 Average Differential Brent-WTI 5.54 9.27 7.15 6 6.76 3.87 WCS at Hardisty(WCS)Average 41.13 19.39 44.27 15 38.46 38.97 Average Differential WTI-WCS 15.83 39.42 12.76 (52)26.31 11.98 Average(C$/bbl)54.29 25.60 58.77 18 49.81 50.56 WCS at Nederland Average 51.47 57.70

144、55.56 (10)62.05 46.18 Average Differential WTI-WCS at Nederland 5.49 1.11 1.47 (46)2.72 4.77 West Texas Sour(WTS)Average 57.26 52.38 56.27 (2)57.24 49.91 Average Differential WTI-WTS (0.30)6.43 0.76 (90)7.53 1.04 Condensate(C5 Edmonton)Average 53.01 45.28 52.86 (13)61.00 51.57 Average Differential W

145、TI-Condensate(Premium)/Discount 3.95 13.53 4.17 11 3.77 (0.62)Average Differential WCS-Condensate(Premium)/Discount (11.88)(25.89)(8.59)(62)(22.54)(12.60)Average(C$/bbl)69.97 59.74 70.15 (11)79.02 66.89 Average Refined Product Prices Chicago Regular Unleaded Gasoline(“RUL”)64.83 66.65 70.55 (10)77.9

146、6 66.95 Chicago Ultra-low Sulphur Diesel(“ULSD”)78.09 84.25 77.97 (10)86.75 69.09 Refining Margin:Average 3-2-1 Crack Spreads(2)Chicago 12.27 13.43 16.00 -15.97 16.77 Group 3 14.60 14.57 16.67 -16.74 16.61 Average Natural Gas Prices AECO(3)(C$/Mcf)2.34 1.90 1.62 6 1.53 2.43 NYMEX(US$/Mcf)2.50 3.64 2

147、.63 (15)3.09 3.11 Foreign Exchange Rate(US$per C$1)Average 0.758 0.758 0.754 (2)0.772 0.771 End of Period 0.770 0.733 0.770 5 0.733 0.797 (1)These benchmark prices are not our realized sales prices and represent approximate values.For our average realized sales prices and realized risk management re

148、sults,refer to the Netback tables in the Reportable Segments sections of this MD&A.(2)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.(3)Alberta Energy Company(“AECO”)natural gas monthly index.Crude Oil Benchmarks In 2019,th

149、e average Brent and WTI crude oil benchmark prices were lower compared with 2018 as uncertainty from oversupply and decreased demand for crude oil due to U.S.-China trade tensions lowered crude oil benchmark pricing.Global prices were supported by the Organization of the Petroleum Exporting Countrie

150、s(“OPEC”)-led production cuts and by U.S.-led sanctions against Venezuela and Iran.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

151、 properties.In 2019,the Brent-WTI differential increased as a result of strong supply growth from the Permian basin,which increased congestion at Cushing,Oklahoma.WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen.In 2019,the average WTI-WCS dif

152、ferential narrowed in response to production curtailments mandated by the Government of Alberta to address record high differentials in the fourth quarter of 2018 and high levels of crude oil in storage.Decreased production due to mandatory curtailments continues to support Alberta benchmark prices.

153、WCS at Nederland is a heavy oil benchmark at the USGC which is representative of our pricing in relation to our 14|CENOVUS ENERGYincreasing sales in the USGC.Heavy crude supply and demand remained tight globally and this was evident in strong pricing at the USGC throughout 2019.Key factors include p

154、roduction cuts between OPEC and their allies,and U.S.sanctions against Venezuela and Iran.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 b

155、etween WTI and WTS benchmark prices narrowed in 2019,due to additional pipeline capacity coming online.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

156、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 conden

157、sate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton.Average condensate benchmark prices were at a wider discount relative to WTI in 2019 compared with 2018 due to increasing North American supply and lower demand as production curtailments in Alb

158、erta were implemented.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 indi

159、cator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI-based crude oil feedstock prices and valued on a last in,first out accounting basis.Average Chicago refined

160、 product prices decreased in 2019 primarily due to lower 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 di

161、fferential between Brent and WTI benchmark prices.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 i

162、s valued on a first in,first out(“FIFO”)accounting basis.15 25 35 45 55 65 75Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4201720182019(average US$/bbl)Historical Crude Oil Benchmark PricesWTIWCS at HardistyWCS at NederlandCondensate5060708090JanFebMarAprMayJuneJulAugSepOctNovDec(average US$/bbl)RUL Refined Product Price

163、2019Q42018Q1Q2Q32017510152025JanFebMarAprMayJuneJulAugSepOctNovDec(average US$/bbl)Chicago 3-2-1 Crack Spread Q42018Q1Q2Q320172019Q4Q1Q2Q314|CENOVUS ENERGY2019 ANNUAL REPORT|15Natural Gas Benchmarks Average AECO prices strengthened during 2019 compared with 2018,however,they remained at low levels p

164、rimarily due to little incremental demand and pipeline maintenance in the Alberta market.The Canada Energy Regulator recently approved a plan to get natural gas into storage during summer maintenance periods to improve intra Alberta supply and demand balances and reduce pricing pressure on AECO.Aver

165、age NYMEX prices decreased compared with 2018 due to increased supply from the continuing 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 ga

166、s 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

167、 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.The Canadian dollar on average weakened relative t

168、o the U.S.dollar in 2019,compared with 2018,resulting in a positive impact of approximately$470 million on our revenues in 2019.The strengthening of the Canadian dollar relative to the U.S.dollar as at December 31,2019 compared with December 31,2018,and the realization of foreign exchange losses on

169、the repayment of our unsecured notes of$412 million,resulted in unrealized foreign exchange gains of$800 million on the translation of our U.S.dollar debt.16|CENOVUS ENERGYREPORTABLE SEGMENTS Our reportable segments are as follows:Oil Sands,which includes the development and production of bitumen in

170、 northeast Alberta.Cenovuss bitumen assets include Foster Creek,Christina Lake and Narrows Lake as well as other projects in the early stages of development.The Companys interest in certain of its operated oil sands properties,notably Foster Creek,Christina Lake and Narrows Lake,increased from 50 pe

171、rcent 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 natu

172、ral 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.publi

173、c company.In addition,Cenovus owns and operates a crude-by-rail terminal in Alberta.This segment coordinates Cenovuss marketing and transportation initiatives to optimize product mix,delivery points,transportation commitments and customer diversification.The marketing of crude oil and natural gas so

174、urced 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 recorde

175、d 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 whic

176、h 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 Companys rail terminal,crude oil production used as feedstock by the Refining and Marketing segment,and un

177、realized intersegment profits in inventory.Eliminations are recorded at transfer prices based on current market prices.On May 17,2017,we acquired from ConocoPhillips Company and certain of its subsidiaries(collectively,“ConocoPhillips”)their 50 percent interest in FCCL,and the majority of ConocoPhil

178、lips western Canadian conventional assets in the Deep Basin in Alberta and British Columbia(“the Acquisition”).In 2017,Cenovus announced its intention to divest of its Conventional segment that included its heavy oil assets at Pelican Lake,the carbon dioxide(“CO2”)enhanced oil recovery project at We

179、yburn 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.As at January 5,2018,all of the Conventional segment assets were sold.Refer to the Discontin

180、ued Operations section of this MD&A for more information.Revenues by Reportable Segment($millions)2019 2018 2017(1)Oil Sands 9,695 9,553 7,132 Deep Basin 662 832 514 Refining and Marketing 10,513 11,183 9,852 Corporate and Eliminations (689)(724)(455)20,181 20,844 17,043 (1)Our 2017 results include

181、229 days of FCCL operations at 100 percent and 229 days of operations from the Deep Basin operations.Oil Sands revenues increased slightly compared with 2018 due to higher realized crude oil pricing,partially offset by higher royalties and lower sales volumes.Deep Basin revenues declined in 2019 com

182、pared with 2018 due to lower sales volumes and realized natural gas liquids pricing,partially offset by lower royalties.2019 ANNUAL REPORT|17Refining and Marketing revenues declined in 2019 compared with 2018.Refining revenues decreased due to lower refined product pricing consistent with the declin

183、e in average refined product benchmark prices.Revenues from third-party crude oil and natural gas sales undertaken by our marketing group increased in 2019 compared with 2018 due to higher crude oil and natural gas volumes partially offset by lower prices.Corporate and Eliminations revenues relate t

184、o sales of natural gas or crude oil and operating revenue between segments and are recorded at transfer prices based on current market prices.Overall,revenues increased in 2018 compared with 2017 primarily due to incremental sales volumes due to the Acquisition and higher refined product pricing,par

185、tially offset by lower realized crude oil and natural gas pricing and higher royalties.OIL SANDS In 2019,we:Managed total production to mandated curtailment requirements;Completed construction of Christina Lake phase G in March,ahead of schedule and below the anticipated capital required;Safely and

186、successfully completed our largest planned turnaround at Christina Lake;Generated Operating Margin of$3,481 million,an increase of$2,395 million compared with 2018 due to higher average realized sales prices,decreased transportation and blending costs,and realized risk management losses of$23 millio

187、n compared with losses of$1,551 million in 2018,partially offset by lower sales volumes and higher royalties;Earned crude oil Netbacks of$27.72 per barrel,excluding realized risk management activities,a 41 percent increase compared with 2018;and Sold more than 25 percent of our Oil Sands production

188、at sales locations outside of Alberta achieving higher realized sales prices.Financial Results($millions)2019 2018(1)2017(1)Gross Sales 10,838 10,026 7,362 Less:Royalties 1,143 473 230 Revenues 9,695 9,553 7,132 Expenses Transportation and Blending 5,152 5,879 3,704 Operating 1,039 1,037 934 (Gain)L

189、oss on Risk Management 23 1,551 307 Operating Margin 3,481 1,086 2,187 Depreciation,Depletion and Amortization 1,543 1,439 1,230 Exploration Expense 18 6 888 Segment Income(Loss)1,920 (359)69 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative inform

190、ation has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.Operating Margin Variance(1)Revenues include the value of condensate sold as heavy oil blend.Condensate costs are recorded in transportation and blending expen

191、se.The crude oil price excludes the impact of condensate purchases.18|CENOVUS ENERGYRevenues Price In 2019,our realized crude oil sales price was$53.78 per barrel compared with$37.51 per barrel in 2018.While WTI benchmark was 12 percent lower than 2018,the narrowing of the WTI-WCS differential by 52

192、 percent to average US$12.76 per barrel(2018 US$26.31 per barrel),the narrower WCS-Christina Dilbit Blend(“CDB”)differential,lower cost of condensate used in blending,and an increase in volumes sold outside of Alberta increased our crude oil sales price.In 2019,we sold more than 25 percent of our pr

193、oduction at sales locations outside of Alberta,contributing to the increase in our realized sales prices.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 decreases relativ

194、e to the price of blended crude oil,our bitumen sales price increases.Due to high demand for condensate at Edmonton,we also purchase condensate from U.S.markets and deliver it to the Edmonton hub.As such,our average cost of condensate is generally higher than the Edmonton benchmark price due to tran

195、sportation between market hubs and transportation to field locations.In addition,up to three months may elapse from when we purchase condensate to when we sell our blended production.In a rising crude oil price environment,we expect to see a positive impact on our bitumen sales price as we are using

196、 condensate purchased at a lower price earlier in the year.The increase in our crude oil price also reflects the narrower WCS-Condensate premium of US$8.59 per barrel(2018 premium of US$22.54 per barrel).Production Volumes(barrels per day)2019 Percent Change 2018 Percent Change 2017 Foster Creek 159

197、,598 (1)161,979 30 124,752 Christina Lake 194,659 (3)201,017 20 167,727 354,257 (2)362,996 24 292,479 Production at Foster Creek and Christina Lake was slightly lower compared with 2018 due to the mandated production curtailments.In the first and fourth quarters of 2018,we made the decision to opera

198、te both facilities at reduced production levels due to limited takeaway capacity and discounted heavy oil pricing.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

199、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 percent to nine percent,based on the Canadian dollar equivalent WTI benchmark price)to the gross revenues from the project.Royalties for a post-pay

200、out project are based on an annualized calculation which uses the greater of:(1)the gross revenues multiplied by the applicable royalty rate(one percent to nine percent,based on the Canadian dollar equivalent WTI benchmark price);or(2)the net profits of the project multiplied by the applicable royal

201、ty rate(25 percent 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 cap

202、ital costs.Foster Creek and Christina Lake are post-payout projects for determining royalties.Our Christina Lake property achieved payout in the third quarter of 2018.Effective Royalty Rates(percent)2019 2018 2017 Foster Creek 18.8 18.0 11.4 Christina Lake 21.6 4.8 2.5 In 2019,royalties increased$67

203、0 million compared with 2018 due to Christina Lake achieving project payout in August 2018 and higher net profits as a result of the mandated curtailment,partially offset by lower annual average WTI benchmark pricing(which determines the royalty rate).Expenses Transportation and Blending Transportat

204、ion and blending costs decreased$727 million to$5,152 million in 2019.Blending costs decreased due to lower condensate costs and a decline in condensate volumes required for our lower production.Our condensate costs were higher than the average Edmonton benchmark price primarily due to the transport

205、ation expense associated with moving the condensate between market hubs and to our oil sands projects.2019 ANNUAL REPORT|19Transportation costs increased primarily due to an increase in volumes shipped by rail and higher pipeline tariff costs from increased U.S.sales.We transported over 25 percent o

206、f our volumes to U.S.destinations,either by pipeline or rail,allowing us to achieve better market prices.Per-unit Transportation Expenses Foster Creek per-unit transportation costs increased$3.36 per barrel to$11.70 per barrel due to higher sales volumes shipped by rail and pipeline to the U.S.and d

207、ecreased total sales volumes,partially offset by IFRS 16 adoption impacts.Christina Lake per-unit transportation costs increased$1.39 per barrel to$6.64 per barrel as a result of higher sales volumes shipped by rail to the U.S.and decreased total sales volumes,partially offset by IFRS 16 adoption im

208、pacts.For further information on the adoption of IFRS 16 refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.Operating Primary drivers of our operating expenses in 2019 were workforce,fuel,repairs and maintenance,chemical costs,and workove

209、rs.Total operating costs were relatively flat compared with 2018 due to higher fuel costs from higher natural gas prices and our decision to maintain steam production levels at pre-curtailment levels,and increased repairs and maintenance,offset by lower chemical costs,lower workforce costs and less

210、workovers.Per-unit Operating Expenses ($/bbl)2019 Percent Change 2018(1)Percent Change 2017(1)Foster Creek Fuel 2.47 16 2.13 (13)2.44 Non-fuel 6.67 (2)6.84 (15)8.02 Total 9.14 2 8.97 (14)10.46 Christina Lake Fuel 2.06 10 1.87 (9)2.06 Non-fuel 5.27 11 4.73 (1)4.78 Total 7.33 11 6.60 (4)6.84 Total 8.1

211、5 7 7.65 (9)8.40 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.At Foster Creek and Christina Lake

212、,per-barrel fuel costs increased due to lower sales volumes,higher natural gas prices and fuel consumption.Steam production levels were maintained at pre-curtailment levels during the year.Per-barrel non-fuel operating expenses at Foster Creek decreased in 2019 compared with 2018 due to lower chemic

213、al costs,less workovers and lower workforce costs partially offset by lower sales volumes.Per-barrel non-fuel operating expenses at Christina Lake increased in 2019 primarily due to lower sales volumes,increased repairs and maintenance and waste,fluid handling and trucking costs due to the planned t

214、urnaround in the second quarter,partially offset by lower chemical costs due to lower bitumen production and a volume related decrease in sulphur treating.Netbacks(1)Foster Creek Christina Lake ($/bbl)2019 2018(2)2017(2)2019 2018(2)2017(2)Sales Price 57.21 42.63 43.75 50.91 33.42 39.78 Royalties 8.4

215、4 6.25 4.00 9.42 1.37 0.87 Transportation and Blending 11.70 8.34 8.73 6.64 5.25 4.52 Operating Expenses 9.14 8.97 10.46 7.33 6.60 6.84 Netback Excluding Realized Risk Management 27.93 19.07 20.56 27.52 20.20 27.55 Realized Risk Management Gain(Loss)(0.16)(11.49)(2.95)(0.19)(11.66)(2.99)Netback Incl

216、uding Realized Risk Management 27.77 7.58 17.61 27.33 8.54 24.56 (1)Netbacks reflect our margin on a per-barrel basis of unblended crude oil.(2)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical A

217、ccounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.20|CENOVUS ENERGYNetback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis.Our Netback calculation is aligned with the definition f

218、ound in the Canadian Oil and Gas Evaluation Handbook(“COGE 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

219、 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 transport it to market.For a reconciliation of our Netback

220、s see the Advisory section of this MD&A.Our average Netback,excluding realized risk management gains and losses,at Foster Creek and Christina Lake increased in 2019 compared with 2018,primarily due to higher realized sales prices,partially offset by higher per-unit royalties,transportation and blend

221、ing costs,operating costs and lower sales volumes.The weakening of the Canadian dollar relative to the U.S.dollar compared with 2018 had a positive impact on our reported sales price of approximately$1.18 per barrel.In 2019,we sold more than 25 percent of our Oil Sands production,at sales locations

222、outside of Alberta,contributing to the increase in our realized sales prices and transportation and blending costs(2018 approximately 18 percent of our Oil Sands production).Risk Management Risk management positions in 2019 resulted in realized losses of$23 million(2018 realized losses of$1,551 mill

223、ion),consistent with average benchmark prices exceeding our contract prices on hedging contracts.DD&A and Exploration Expense 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

224、to date,together with estimated 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 equ

225、ivalent 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.We depreciate our ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease term.In 2019,Oil Sands DD&A

226、was$1,543 million and increased compared with 2018 due to an increase in our average depletion rate,partially offset by lower sales volumes and additional depreciation expense on our ROU assets.Our depletion rate increased as a result of higher future development costs due to additional capital requ

227、ired to improve recovery performance and develop thin pay volumes at Christina Lake and Foster Creek,as well as an increase in maintenance capital at Foster Creek.The average depletion rate for the year ended December 31,2019 was approximately$11.15 per barrel(2018$10.60 per barrel).Exploration expe

228、nse of$18 million was recorded for the year ended December 31,2019(2018$6 million)related to previously capitalized E&E costs written off as the carrying value was not considered to be recoverable.Capital Investment ($millions)2019 2018(1)2017(1)Foster Creek 243 379 455 Christina Lake 362 445 426 60

229、5 824 881 Other(2)101 63 92 Capital Investment(3)706 887 973 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section of

230、this MD&A for further information.(2)Includes new resource plays,Marten Hills,Narrows Lake,Telephone Lake and Athabasca natural gas.(3)Includes expenditures on PP&E and E&E assets.In 2019,Oil Sands capital investment was$706 million,$181 million lower compared with 2018 mainly due to a continued foc

231、us on capital discipline,reduced spending on sustaining well programs,completion of Christina Lake phase G construction,a smaller stratigraphic test well program and deferred capital spending due to the mandatory curtailment.At Foster Creek,capital investment focused on sustaining capital related to

232、 existing production and stratigraphic test wells.Christina Lake capital investment focused on sustaining capital related to existing production,stratigraphic test wells,and the completion of the phase G construction in March.Other capital investment related to advancing key initiatives and technica

233、l development costs.2019 ANNUAL REPORT|21Drilling Activity Gross Stratigraphic Test Wells Gross ProductionWells(1)2019 2018 2017 2019 2018 2017 Foster Creek 14 43 96 -14 41 Christina Lake 18 63 108 11 38 25 32 106 204 11 52 66 Other 26 23 16 11 3 -58 129 220 22 55 66 (1)SAGD well pairs are counted a

234、s 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 Oil Sands capital investment for 2020 is forecast to be between$

235、865 million and$1,010 million.2020 guidance dated December 9,2019 is available on our website at .Foster Creek capital investment for 2020 is forecast to be between$360 million and$410 million.We plan to continue focusing on sustaining capital related to existing production.Christina Lake capital in

236、vestment for 2020 is forecast to be between$310 million and$360 million focused on sustaining capital.Field construction of phase G was completed at the end of the first quarter of 2019 and is well positioned to bring on oil production in the first quarter of 2020 and ramp up towards its nameplate c

237、apacity of 50,000 barrels per day throughout 2020.In 2020,we plan to spend capital on Foster Creek phase H,Christina Lake phase H and Narrows Lake to continue to advance each opportunity to sanction-ready status.In 2020,our Technology and other capital investment,is forecast to be between$160 millio

238、n and$190 million,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.DEEP BASIN In 2019,we:Produced a total of 97,423 BOE per day,a decrease com

239、pared with 2018 due to natural declines from lower sustaining capital investment,the divestiture of CPP and temporary well shut-ins for low natural gas prices;Delivered total operating cost reductions by optimizing operations,focusing on well interventions,maintenance and repair activities and lever

240、aging our infrastructure;Generated Operating Margin of$242 million,a decrease of$70 million due to lower volumes and natural gas liquids prices,partially offset by lower operating expenses,royalties,realized risk management activities,and transportation and blending costs;and Earned a Netback of$6.0

241、2 per BOE,excluding realized risk management activities.Financial Results($millions)2019 2018(1)May 17-December 31,2017(1)Gross Sales 691 904 555 Less:Royalties 29 72 41 Revenues 662 832 514 Expenses Transportation and Blending 82 90 56 Operating 337 403 250 Production and Mineral Taxes 1 1 1 (Gain)

242、Loss on Risk Management -26 -Operating Margin 242 312 207 Depreciation,Depletion and Amortization 319 412 331 Exploration Expense 64 2,117 -Segment Income(Loss)(141)(2,217)(124)(1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not b

243、een restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.22|CENOVUS ENERGYOperating Margin Variance Revenues Price 2019 2018 May 17-December 31,2017 Light and Medium Oil($/bbl)65.70 66.71 60.01 NGLs($/bbl)26.36 38.56 33.05 Natural

244、Gas($/mcf)2.01 1.72 2.03 Total Oil Equivalent($/BOE)17.95 19.31 19.52 For the year ended December 31,2019,revenues declined due to lower volumes and realized liquids sales prices,partially offset by an increase in our realized natural gas sale price.In 2019,revenues included$53 million of processing

245、 fee revenue related to our interests in natural gas processing facilities(2018$57 million).We do not include processing fee revenue in our per-unit pricing metrics or our Netbacks.Production Volumes 2019 2018 2017(1)Liquids Crude Oil(barrels per day)4,911 5,916 3,922 NGLs(barrels per day)21,762 26,

246、538 16,928 26,673 32,454 20,850 Natural Gas(MMcf per day)424 527 316 Total Production(BOE/d)97,423 120,258 73,492 Natural Gas Production(percentage of total)73 73 72 Liquids Production(percentage of total)27 27 28 (1)From the closing of the Acquisition on May 17,2017 to December 31,2017,production a

247、veraged 117,138 BOE per day.Production in 2019 decreased from 2018 due to natural declines from lower sustaining capital investment,the divestiture of CPP and temporary well shut-ins for low natural gas prices.CPP was sold on September 6,2018 and produced approximately 6,523 BOE per day for the twel

248、ve months ended December 31,2018.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

249、the Gas Cost Allowance(“GCA”),which reduces royalties,to account for capital and operating costs incurred to process and transport the Crowns portion of natural gas production.In British Columbia,royalties also benefit from programs to reduce the rate on natural gas production.British Columbia appli

250、es 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 Crowns portion of natural gas production.In 2019,our effective royalty rate was 8.7 percent for liquids(2018

251、12.8 percent)and 1.1 percent for natural gas(2018 3.6 percent)due to GCA royalty credits being higher than the royalty expenses,resulting in negative royalty rates in certain months of 2019,and declines in price and production.2019 ANNUAL REPORT|23Expenses Transportation Per unit transportation cost

252、s averaged$2.31 per BOE compared with$1.97 per BOE in 2018,due to higher pipeline tariffs.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 Alber

253、ta market.Operating Total operating costs decreased 16 percent to$337 million(2018$403 million)as a result of the divestiture of CPP,optimizing operations,focusing on well interventions,maintenance and repair activities and leveraging our infrastructure to lower the cost structure.While total operat

254、ing costs have declined significantly,per-unit operating costs increased slightly averaging$8.79 per BOE in 2019(2018$8.58 per BOE).The increase in per-unit operating costs was driven by lower sales volumes,partially offset by decreased third-party processing fees due to less throughput and from lev

255、eraging our infrastructure to reduce fees paid,lower repairs and maintenance activity,decreased property tax and lease costs and lower workforce costs.Netbacks($/BOE)2019 2018(1)May 17-December 31,2017(1)Sales Price 17.95 19.31 19.52 Royalties 0.81 1.64 1.54 Transportation and Blending 2.31 1.97 2.0

256、8 Operating Expenses 8.79 8.58 8.56 Production and Mineral Taxes 0.02 0.03 0.02 Netback Excluding Realized Risk Management 6.02 7.09 7.32 Realized Risk Management Gain(Loss)(0.01)(0.59)-Netback Including Realized Risk Management 6.01 6.50 7.32 (1)IFRS 16 was adopted January 1,2019 using the modified

257、 retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.Risk Management Risk management activities in 2019 were minimal(2018 realized losses of$26 million).DD&A an

258、d Exploration Expense 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,calc

259、ulated 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 a

260、sset as represented by proved reserves.The average depletion rate was approximately$9.15 per BOE year ended December 31,2019(2018$10.55 per BOE,respectively).For the year ended December 31,2019 total Deep Basin DD&A was$319 million(2018$412 million).The decrease was due to lower sales volumes and a

261、lower depletion rate.Exploration expense of$64 million was recorded for the year ended December 31,2019 compared with$2.1 billion in 2018 resulting from previously capitalized E&E costs written off as a result of Managements review of the Deep Basin development plan.Capital Investment In 2019,we inv

262、ested$53 million compared with$211 million in 2018.2019 investment focused on the disciplined development of our Deep Basin assets,which included maintaining safe and reliable operations,as well as the completion and tie-in of well inventories from the previous years development program.($millions)2

263、019 2018 May 17-December 31,2017 Drilling and Completions 4 111 152 Facilities 20 56 32 Other 29 44 41 Capital Investment(1)53 211 225 (1)Includes expenditures on PP&E and E&E assets.24|CENOVUS ENERGYDrilling Activity In 2019,there were two net wells completed and three net wells tied-in.In 2018,the

264、re were 15 net horizontal wells drilled,21 net wells completed,and 25 net wells tied-in.Future Capital Investment In 2020,Deep Basin capital investment is forecast to be between$80 million and$95 million.We continue to take a disciplined approach to the development of our Deep Basin assets consideri

265、ng factors such as well inventory,pace of development,infrastructure constraints,economic thresholds and limited capital spending on the assets going forward.2020 Guidance dated December 9,2019 is available on our website at .REFINING AND MARKETING In 2019,we:Achieved crude oil runs averaging 443,00

266、0 barrels per day,consistent with 2018 and attained a record monthly crude oil run rate in July at Wood River;Increased rail volumes loaded at the Bruderheim crude-by-rail terminal,averaging 65,293 barrels per day compared with 37,988 barrels per day in 2018.We exited the year with loaded volumes av

267、eraging 101,014 barrels per day;and Generated Operating Margin of$737 million,a decrease of$259 million compared with 2018.While market crack spreads were relatively unchanged year over year,realized crack spreads were down due to narrowing medium sour and heavy crude oil differentials resulting in

268、lower crude advantage.Financial Results($millions)2019 2018(1)2017(1)Revenues 10,513 11,183 9,852 Purchased Product 8,844 9,261 8,476 Gross Margin 1,669 1,922 1,376 Expenses Operating 948 927 772 (Gain)Loss on Risk Management (16)(1)6 Operating Margin 737 996 598 Depreciation,Depletion and Amortizat

269、ion 280 222 215 Segment Income(Loss)457 774 383 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.Ref

270、inery Operations(1)2019 2018 2017 Crude Oil Capacity(Mbbls/d)(2)482 460 460 Crude Oil Runs(Mbbls/d)443 446 442 Heavy Crude Oil 177 191 202 Light/Medium 266 255 240 Refined Products(Mbbls/d)466 470 470 Gasoline 223 233 238 Distillate 167 156 149 Other 76 81 83 Crude Utilization(percent)92 97 96 (1)Re

271、presents 100 percent of the Wood River and Borger refinery operations.Cenovuss interest is 50 percent.(2)Effective January 1,2020,our Refineries have crude oil nameplate capacity of 495,000 gross barrels per day.On a 100 percent basis,the Refineries had total processing capacity in 2019 of 482,000 g

272、ross 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.Effective January 1,2020,as a result of new maximum demonstrated rates in 2019,Wood River was re-rated,increasing our total cru

273、de oil processing nameplate capacity to 495,000 gross barrels per day including processing capability of up to 275,000 gross barrels per day of blended heavy crude oil.The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil production.Process

274、ing less expensive crude oil relative to WTI creates a feedstock cost advantage,illustrated by the discount of both WCS and 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 optim

275、ized 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.2019 ANNUAL REPORT|25Crude oil runs and refined product output in 2019 remained consistent compared with 2018.Operational perfo

276、rmance in 2019 was impacted by the unplanned maintenance and outages,including a fire in the crude unit at Wood River in the first quarter,and planned turnaround activities at the Refineries in the fourth quarter.Both Refineries had major planned turnarounds in 2018.Crude-By-Rail Terminal We continu

277、e to increase total rail volumes loaded at our Bruderheim crude-by-rail terminal.In 2019,we loaded an average of 65,293 barrels per day(45,324 barrels per day of our volumes)from our Bruderheim crude-by-rail terminal compared with an average of 37,988 barrels per day(28,531 barrels per day of our vo

278、lumes)in 2018.Gross Margin 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 be

279、tween 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 2019,Refining and Marketing gross margin decreased$253 million.While market crack spreads were relatively unchanged

280、 year over year,realized crack spreads were down due to narrowing medium sour and heavy crude oil differentials which resulted in lower crude advantage,partially offset by higher margins on fixed priced products associated with a lower benchmark WTI,and a reduction in the cost of RINs.Our gross marg

281、in was positively impacted by approximately$37 million for the year ended December 31,2019,due to the weakening of the Canadian dollar relative to the U.S.dollar.For the year ended December 31,2019,the cost of RINs was$99 million(2018$131 million).RIN costs declined,primarily due to the decrease in

282、RINs benchmark prices as a result of small refiners being granted exemptions from volume obligations.Operating Expense Primary drivers of operating expenses in 2019 were maintenance,labour and utilities.Refining operating expenses increased due to the weakening of the Canadian dollar relative to the

283、 U.S dollar.Marketing operating expense increased$14 million due to higher rail transportation and workforce costs.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 t

284、o 60 years.The service lives of these assets are reviewed on an annual basis.ROU assets are depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term.Refining and Marketing DD&A was$280 million compared with$222 million in 2018.The increase is

285、primarily attributable to depreciation of our ROU assets which commenced January 1,2019 on the adoption of IFRS 16.Capital Investment($millions)2019 2018(1)2017(1)Wood River Refinery 128 119 114 Borger Refinery 100 85 54 Marketing 52 4 12 Capital Investment 280 208 180 (1)IFRS 16 was adopted January

286、 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section of this MD&A for further information.Capital expenditures in 2019 focused primarily on capital

287、 maintenance projects and yield enhancements as well as strategic rail initiatives and infrastructure.In 2020,we expect to invest between$285 million and$330 million and will continue to focus on capital maintenance,reliability work and yield improvement projects.Our 2020 guidance dated December 9,2

288、019 is available on our website at .CORPORATE AND ELIMINATIONS In 2019,our risk management activities resulted in unrealized risk management losses of$149 million(2018 gains of$1,249 million).26|CENOVUS ENERGYExpenses($millions)2019 2018(1)2017(1)General and Administrative 336 391 300 Onerous Contra

289、ct Provisions (5)629 8 Finance Costs 511 627 645 Interest Income (12)(19)(62)Foreign Exchange(Gain)Loss,Net (404)854 (812)Revaluation(Gain)-(2,555)Transaction Costs -56 Re-measurement of Contingent Payment 164 50 (138)Research Costs 20 25 36 (Gain)Loss on Divestiture of Assets (2)795 1 Other(Income)

290、Loss,Net (11)(12)(5)597 3,340 (2,526)(1)IFRS 16 was adopted January 1,2019 using the modified retrospective approach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.General and Ad

291、ministrative Primary drivers of our general and administrative expenses were workforce costs,employee long-term incentive costs and operating costs associated with our real estate portfolio.In 2019,general and administrative expenses decreased$55 million primarily due to lower rent expense of$42 mil

292、lion compared with$134 million in 2018 primarily from the adoption of IFRS 16,lower headcount and minimal severance costs in 2019 compared with$60 million of severance costs in 2018,partially offset by higher employee long-term incentive costs(2019$98 million;2018$9 million).Onerous Contract Provisi

293、ons In 2019,due to the adoption of IFRS 16,onerous contract provisions are composed of non-lease components of real estate contracts which consist of operating costs and unreserved parking.In 2018,onerous contract provisions included the lease components of base rent and reserved parking as well as

294、the non-lease components.For further information on the adoption of IFRS 16 refer to Note 4 of the Consolidated Financial Statements.In 2019,we recorded a non-cash recovery for onerous contracts of$5 million,due to an update in the underlying assumptions associated with certain Calgary office space(

295、2018 expense of$629 million).Finance Costs In 2019,finance costs decreased by$116 million compared with 2018 due to the significant reduction of total debt and a discount of$63 million on the repurchase of unsecured notes in 2019,partially offset by an increase in interest of$82 million related to l

296、ease liabilities from the adoption of IFRS 16.The weighted average interest rate on outstanding debt for the year ended December 31,2019 was 5.1 percent(2018 5.1 percent).Foreign Exchange ($millions)2019 2018 2017 Unrealized Foreign Exchange(Gain)Loss (827)649 (857)Realized Foreign Exchange(Gain)Los

297、s 423 205 45 (404)854 (812)In 2019,unrealized foreign exchange gains of$827 million were recorded primarily as a result of the translation of our U.S.dollar denominated debt.The Canadian dollar relative to the U.S.dollar as at December 31,2019 was stronger compared with December 31,2018.For the year

298、 ended December 31,2019,realized foreign exchange losses of$423 million,were recorded primarily as a result of the recognition of foreign exchange losses from the repurchase of debt.Re-measurement of Contingent Payment Related to oil sands production,Cenovus has agreed to make quarterly payments to

299、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 is$6 million for each dollar that the WCS price exceeds$52 per barrel.There are no maximum payme

300、nt 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$143 million as at Decembe

301、r 31,2019 was estimated by calculating the present value of the future expected cash flows using an 2019 ANNUAL REPORT|27option 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 3

302、1,2019,a non-cash re-measurement loss of$164 million was recorded.As at December 31,2019,average WCS forward pricing for the remaining term of the contingent payment is$46.57 per barrel.Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately$41.20 p

303、er barrel and$54.60 per barrel.DD&A Corporate and Eliminations DD&A includes provisions in respect of corporate assets,such as computer equipment,leasehold improvements,office furniture,and ROU assets.Costs associated with corporate assets are depreciated on a straight-line basis over the estimated

304、service life of the assets,which range from three to 25 years.The service lives of these assets are reviewed on an annual basis.ROU assets(real estate assets)are depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term.DD&A in 2019 was$107 mil

305、lion(2018$58 million).The increase in DD&A compared with 2018 was due to depreciation expense on our ROU assets.Income Tax ($millions)2019 2018 2017 Current Tax Canada 14 (128)(217)United States 3 2 (38)Current Tax Expense(Recovery)17 (126)(255)Deferred Tax Expense(Recovery)(814)(884)203 Total Tax E

306、xpense(Recovery)From Continuing Operations (797)(1,010)(52)The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:($millions)2019 2018 2017 Earnings(Loss)From Continuing Operations Before Income Tax 1,397 (3,926)2,216 Canadian Statutory R

307、ate(percent)26.5 27.0 27.0 Expected Income Tax Expense(Recovery)From Continuing Operations 370 (1,060)598 Effect of Taxes Resulting From:Foreign Tax Rate Differential (52)(57)(17)Non-Taxable Capital(Gains)Losses (38)89 (148)Non-Recognition of Capital(Gains)Losses (39)87 (118)Adjustments Arising from

308、 Prior Year Tax Filings 4 3 (41)Recognition of Previously Unrecognized Capital Losses -(68)Recognition of U.S.Tax Basis (387)(78)-Change in Statutory Rates (671)-(275)Non-Deductible Expenses -3 (5)Other 16 3 22 Total Tax Expense(Recovery)From Continuing Operations (797)(1,010)(52)Effective Tax Rate(

309、percent)(57.1)25.7 (2.3)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,i

310、ncome 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.For the year ended December 31,2019,a current tax expense was recorded compared with a recovery in 2018 and 2017

311、due to the carry back of losses to recover tax paid in previous years.The maximum recovery was reached in 2018.In 2019,the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to eight percent over four years.As a result,we recorded a deferred income tax rec

312、overy of$671 million for the year ended December 31,2019.In addition,we have recorded a deferred income tax recovery of$387 million due to an internal restructuring of our U.S.operations resulting in a step-up in the tax basis of our refining assets.In 2018,we recorded a deferred tax recovery relate

313、d 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 the Companys refining assets.The increase in tax basis was a result of the Companys partner recognizing a taxable gain on its interest in WRB,whic

314、h due to an election filed with the U.S.tax authorities,was added to the tax basis of WRBs assets.A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in 28|CENOVUS ENERGYconnection with the Acquisition,net of a reduction of the U.S.federal corporate i

315、ncome tax rate from 35 percent to 21 percent reducing our deferred income tax liability and the impact of E&E write-downs.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 fro

316、m 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 t

317、he provision and the actual amounts subsequently reported on the tax returns,and other permanent differences.Capital Investment Capital expenditures of$137 million for the year ended December 31,2019 focused primarily on the build-out of office space at Brookfield Place Calgary and information techn

318、ology capital.In 2020,we expect to invest between$90 million and$100 million,which includes continued investments in technology and equipment to further modernize our workplace,improve our cost structure and better manage risk.Guidance dated December 9,2019 is available on our website at .DISCONTINU

319、ED OPERATIONS 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.After-tax earnings from discontinued operations for the year ended December 31,2018 were$27 million.An after-tax

320、gain on discontinuance of$220 million was recorded on the sale.2019 ANNUAL REPORT|29QUARTERLY RESULTS Our results over the last four quarters were impacted primarily by mandatory production curtailments and the last eight quarters were impacted by volatility in commodity prices.Light oil benchmark p

321、rices remained depressed throughout the majority of 2019,consistent with the substantial fall in the price of WTI in the fourth quarter of 2018,due to continued uncertainty from oversupply,decreased demand and trade tensions compared with the price improvements throughout the first three quarters of

322、 2018.The mandatory production curtailments significantly narrowed light-heavy crude oil differentials in Alberta and reduced crude price spread between the USGC and Alberta in 2019 compared with 2018.As a result,our Operating Margin from continuing operations was$864 million in the fourth quarter o

323、f 2019,a substantial increase from$135 million in the fourth quarter of 2018.Net Earnings from continuing operations was$113 million compared with a loss of$1,350 million in 2018.Selected Operating and Consolidated Financial Results($millions,except per share 2019 2018(1)amounts)Q4 Q3 Q2 Q1 Q4 Q3 Q2

324、 Q1 Production Volumes Liquids(barrels per day)400,329 380,699 371,390 370,983 354,592 408,950 423,340 395,474 Natural Gas(MMcf per day)403 407 432 458 469 520 572 558 Total Production(BOE per day)467,448 448,496 443,318 447,270 432,714 495,608 518,609 488,561 Total Production From Continuing Operat

325、ions(BOE per day)467,448 448,496 443,318 447,270 432,713 495,592 518,530 487,464 Refinery Operations Crude Oil Runs(Mbbls/d)456 465 474 375 477 492 464 349 Refined Products(Mbbls/d)477 485 501 402 502 518 490 369 Revenues 4,838 4,736 5,603 5,004 4,545 5,857 5,832 4,610 Operating Margin from Continui

326、ng Operations(2)864 1,080 1,277 1,239 135 1,191 911 157 Cash From Operating Activities From Continuing Operations 740 834 1,275 436 488 1,258 506 (134)Total 740 834 1,275 436 485 1,259 533 (123)Adjusted Funds Flow(3)678 916 1,082 1,048 (36)977 774 (41)Operating Earnings(Loss)from Continuing Operatio

327、ns(3)(164)284 267 69 (1,670)(41)(292)(752)Per Share($)(4)(0.13)0.23 0.22 0.06 (1.36)(0.03)(0.24)(0.61)Net Earnings(Loss)From Continuing Operations 113 187 1,784 110 (1,350)(242)(410)(914)Per Share($)(4)0.09 0.15 1.45 0.09 (1.10)(0.20)(0.33)(0.74)Total Net Earnings(Loss)113 187 1,784 110 (1,356)(241)

328、(418)(654)Per Share($)(4)0.09 0.15 1.45 0.09 (1.10)(0.20)(0.34)(0.53)Capital Investment(5)317 294 248 317 276 271 292 524 Dividends 77 60 62 61 62 61 62 60 Per Share($)0.0625 0.0500 0.0500 0.0500 0.0500 0.0500 0.0500 0.0500 (1)IFRS 16 was adopted January 1,2019 using the modified retrospective appro

329、ach;therefore,comparative information has not been restated.Refer to the Critical Accounting Judgments,Estimation Uncertainties and Accounting Policies section in this MD&A.(2)Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements,in Notes 1 and 7 of the Interim Consoli

330、dated Financial Statements and defined in this MD&A.(3)Non-GAAP measure defined in this MD&A.(4)Represented on a basic and diluted per share basis.(5)Includes expenditures on PP&E,E&E assets,and assets held for sale.Fourth Quarter 2019 Results Compared With the Fourth Quarter 2018 Production Volumes

331、 Total production from continuing operations increased eight percent in the fourth quarter of 2019 compared with 2018.In the fourth quarter of 2018,we decided to restrict oil sands production rates in response to takeaway capacity constraints and the wide heavy oil differentials.In the fourth quarte

332、r of 2018,the WTI-WCS differential averaged US$39.42 per barrel and reached a record of US$52.00 per barrel.In the fourth quarter of 2019,we sold 181,366 barrels per day,approximately 35 percent,of our Oil Sands production at sales locations outside of Alberta compared with 99,041 barrels per day,ap

333、proximately 20 percent,in the fourth quarter of 2018.Deep Basin production in the fourth quarter of 2019 decreased 12 percent to 93,317 BOE per day mainly due to natural declines from lower sustaining capital investment.30|CENOVUS ENERGYRefining and Marketing Operations Crude oil runs of 456,000 gross barrels per day and refined product output of 477,000 gross barrels per day were lower compared w