UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 under the Securities Exchange Act of 1934

 

  For April 2021    Commission File Number: 1-34513        

 

 

 

CENOVUS ENERGY INC.

(Translation of registrant’s name into English)

4100, 225 6 Avenue S.W.

Calgary, Alberta, Canada T2P 1N2

(Address of principal executive office)

 

 

 

 

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ☐    Form 40-F ☒

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):              

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):              

DOCUMENTS FILED AS PART OF THIS FORM 6-K

See the Exhibit Index to this Form 6-K.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: April 8, 2021

 

            CENOVUS ENERGY INC.   
                        (Registrant)   
  By:                  /s/ Elizabeth McNamara                       
                Name:   Elizabeth McNamara   
                Title:     Assistant Corporate Secretary   

Form 6-K Exhibit Index

 

  Exhibit No.     
99.1    2020 Annual Report


Table of Contents

Exhibit 99.1

 

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Indigenous Housing Initiative

Investing in, and working with, Indigenous communities near our operations to ensure they share in the benefits of resource development has always been part of how we do business.

We talked to Indigenous communities about what they needed and in 2020 Cenovus announced its initial five-year, $50-million Indigenous Housing Initiative, to build about 200 homes in six First Nation and Métis communities in northern Alberta. It’s the largest community investment in our company’s history and an important way for us to contribute meaningfully, by addressing one of the most pressing issues facing Indigenous communities in Canada today — lack of adequate housing.

We’ve also partnered with Portage College, creating a training program to provide members of communities participating in the initiative with the opportunity to learn valuable trade skills that will enable them to take part in building and maintaining homes.

Participating communities:

 

•   Beaver Lake Cree Nation

 

•   Chard Métis (Local 218)

 

•   Chipewyan Prairie Dene First Nation

 

•   Cold Lake First Nations

 

•   Conklin Métis (Local 193)

 

•   Heart Lake First Nation

Progress in 2020

Even with COVID-19-related challenges, 12 homes were built in 2020 and more are under construction. The first residents began moving into their new homes in February 2021.

 

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Our response to COVID-19

We began to monitor and respond to the COVID-19 pandemic early in 2020, with dedicated teams developing and implementing proactive measures to protect the health and safety of our workers and the continuity of our business.

Cenovus established comprehensive COVID-19 protocols, including enhanced cleaning, physical distancing and health screening measures for our staff. We moved to essential staffing at our field sites and initially gave office staff the flexibility to work remotely, followed by mandatory work-from-home measures for office staff based on evolving guidance from public health officials.

We are impressed by the resilience and agility of our people and will continue to put them first in every decision we make, as we ensure the appropriate protocols remain in place for as long as required based on the advice and direction of government, public health officials and Cenovus’s internal health and safety experts.

 

 

 

TABLE OF CONTENTS

  
       1   OUR HISTORY  
  2   MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER  
  4   MESSAGE FROM OUR BOARD CHAIR  
  5   MANAGEMENT’S DISCUSSION AND ANALYSIS  
  67   CONSOLIDATED FINANCIAL STATEMENTS  
  78   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  
  124   SUPPLEMENTAL INFORMATION  
  127   ADVISORY  
  141     INFORMATION FOR SHAREHOLDERS  
 

For 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 127.

 

      
 

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WE’RE A CANADIAN-BASED INTEGRATED ENERGY COMPANY

Headquartered in Calgary, Alberta, Cenovus operates in Canada, the United States and the Asia Pacific region. Our upstream operations include oil sands projects in northern Alberta, thermal and conventional crude oil and natural gas projects across Western Canada, crude oil production offshore Newfoundland and Labrador and natural gas and liquids production offshore China and Indonesia. Cenovus’s downstream operations include upgrading, refining and marketing operations in Canada and the United States.

Cenovus is the third largest Canadian oil and natural gas producer and the second largest Canadian-based refiner and upgrader.

 

OUR HISTORY

Cenovus began independent operations on December 1, 2009 when Encana Corporation - now Ovintiv - split into two distinct companies.

Many of Cenovus’s original assets came from PanCanadian Energy Corporation and Alberta Energy Company, which merged to form Encana in 2002.

Through those two companies, we can trace our roots to the 1880s when the Government of Canada commissioned Canadian Pacific Railway (CPR) to build a transcontinental railroad. As part of its payment, CPR received 25 million acres of land, some of which included mineral and surface rights. It was a CPR crew drilling for water near Medicine Hat in 1883 that made Alberta’s first natural gas discovery and launched the petroleum era in Western Canada. PanCanadian Energy eventually emerged from that first discovery.

Alberta Energy Company came into being in the 1970s, when the Government of Alberta created it to provide Albertans and other

 

Canadians with an opportunity to participate, through share ownership, in the industrial and energy-related growth of the province.

On January 1, 2021 Cenovus acquired Husky Energy. Husky began as a small refinery operation in Wyoming in 1938 and became one of Canada’s larger integrated oil and natural gas companies, with operations in Western and Atlantic Canada, the United States and the Asia Pacific region.

Husky opened its first Canadian refinery in Lloydminster in 1947. The company’s offshore exploration efforts began in Newfoundland and Labrador in 1981, and in 1997 Husky announced a joint venture oil exploration agreement offshore China with CNOOC. Husky added steam assisted gravity drainage projects to its production, starting in 2001 and purchased refineries in Lima, Ohio and Superior, Wisconsin in 2007 and 2017 respectively.

 

 

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In many ways, 2020 was unprecedented for our industry and our company. We began the year on solid financial footing, having delivered strong free funds flow in 2019 while also reducing our net debt by 22 percent. We were well on the way to reaching our balance sheet goals, our operations continued to perform well, we had fully ramped up our crude-by-rail program and we were beginning to see the full benefit of additional production from Christina Lake Phase G. We were also clearly demonstrating Cenovus’s commitment to sustainability. In January 2020, we published bold environmental, social and governance (ESG) targets in four key areas for the company, including our ambition to achieve net zero emissions by 2050. In addition, we announced our Indigenous Housing Initiative — the largest community investment in Cenovus’s history. It’s an initial five-year, $50-million program to build much needed homes in six First Nation and Métis communities closest to our oil sands operations in northern Alberta.

Then, early in the year, the macro-economic environment deteriorated quickly. In a fight over market share, Saudi Arabia and Russia stopped their cooperation to manage global crude oil supplies, and COVID-19 hit, causing significant demand destruction for our industry’s products. These events led to a collapse in benchmark oil prices from the beginning of March to early May, followed by a slow and volatile recovery throughout the rest of the year. This resulted in a substantial impact to our bottom line in 2020, accompanied by a sharp drop in share prices across the entire energy sector, including Cenovus’s shares. Despite these external forces, Cenovus continued to deliver safe and reliable operations and performed well on the factors that were within our control.

To ensure the health and safety of our employees and the communities in which we operate, we responded swiftly to the COVID-19 pandemic, introducing enhanced cleaning and physical distancing measures, moving to essential staffing at our field sites and ultimately introducing mandatory work-from-home measures for the vast majority of our office staff. We continue to follow the guidance and direction of governments, public health officials and our company’s internal health and safety experts as COVID-19 measures evolve.

To help maintain our financial resilience as we faced the difficult economic environment, early in the year we reduced our planned capital spending by a total of 43 percent in March and April and temporarily suspended our dividend. We strategically

managed our oil sands assets, leveraging the flexibility of our business to reduce production in April, then reacting quickly to price signals to start ramping up in May and June, maximizing the benefit of an early recovery in prices. We also purchased production curtailment credits available in the market to produce above the Government of Alberta’s mandated limit when prices were higher. And as commodity prices further strengthened in the second half of the year, we restarted our crude-by-rail program in the fourth quarter to maximize cash flows.

Our flexible capital and operating strategy in 2020 preserved liquidity and with the gradual recovery in oil prices towards the end of the year, we generated positive free funds flow in the fourth quarter, helping offset the impact of low oil prices on our full-year results. Most importantly, despite the challenges facing our industry, our commitment to best-in-class safety performance remained our top priority. We achieved year-over-year safety improvements at our operations, recording a significant incident frequency of 0.01 compared with 0.14 the previous year and two process safety events compared with eight in 2019.

In 2020, Cenovus’s share price traded largely in line with our peers while underperforming the S&P/TSX Composite and S&P/TSX Energy Indexes, as you can see from the total shareholder return chart. The gradual recovery in our share price over the course of last year accelerated following the October 25 announcement of our plan to combine with Husky Energy and was in line with the overall recovery in benchmark crude oil prices in late 2020 and early 2021. From the date of the Husky announcement to the end of February, our share price increased 93 percent, compared with 76 percent for our broader peer group of integrated producers, 86 percent for our oil sands peer group and 61 percent for the S&P/TSX Capped Energy Index. During the same period, benchmark West Texas Intermediate (WTI) prices increased 54 percent, while the S&P/TSX Composite Index increased by 11 percent.

On January 1 of this year, we successfully closed the Husky transaction, creating a resilient integrated energy leader. The combination addressed three key strategic priorities for our company: continuing to improve our cost structure, enhancing our market access and deleveraging our balance sheet.

In 2021, we expect to achieve nearly $1 billion of synergies, putting us firmly on track to reach at least $1.2 billion in annual run-rate synergies. Our strong portfolio of well-matched

 

 

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upstream production and midstream and downstream assets creates a global competitor able to optimize margin capture across the heavy oil value chain, while largely mitigating exposure to light-heavy oil price differentials and maintaining a healthy exposure to global commodity prices.

Our enhanced financial strength sets the foundation for a business that will be resilient in virtually any commodity price scenario, with a robust and more stable free funds flow stream allowing us to accelerate the deleveraging of our balance sheet and return more value to shareholders. Following the completion of the Husky transaction, Moody’s Investors Service upgraded Cenovus to investment grade Baa3, while DBRS Limited upgraded us to BBB from BBB (low). And S&P Global Ratings confirmed our BBB- rating while Fitch Ratings maintained its BB+ rating.

We have already delivered on our commitment to reinstate a dividend after closing the Husky transaction. In 2021 and beyond, we will remain focused on maintaining and enhancing our investment grade status, supporting our industry-leading cost structure, ensuring disciplined capital investment and deleveraging our balance sheet. We’ve budgeted about $2.1 billion in sustaining

capital to deliver upstream production of approximately 755,000 barrels of oil equivalent per day and downstream throughput of approximately 525,000 barrels per day. We remain committed to continuing to allocate free funds flow to reduce our net debt to less than $10 billion, with a longer-term target to get our net debt down to $8 billion or below.

We are also focused on world-class safety performance and ESG leadership. This includes an ongoing commitment to transparent performance reporting as well as our ambition to achieve net zero emissions by 2050 and a plan to set ambitious new ESG targets for the combined company later in 2021.

The resilience and adaptability of our staff were fundamental to the company’s performance in 2020. Thanks to their efforts and the decisive steps we took as a company during an incredibly challenging economic environment, we are even stronger today than we were a year ago, and I am extremely optimistic about our future.

/s/ Alex Pourbaix

President & Chief Executive Officer

 

 

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Cenovus skillfully navigated uncharted territory in 2020 as our industry faced persistently unstable commodity prices and jittery capital markets throughout much of the year. With weakening oil prices arising from the Saudi-Russia price war and the reduction in energy demand due to the COVID-19 pandemic, management responded quickly to get ahead of the deteriorating economic environment early in the year. Cenovus reduced capital and operating plans to preserve liquidity, while also strategically leveraging the company’s low-cost, low-decline assets and highly capable workforce to maintain safe and reliable operations. The company also took swift and appropriate measures to protect the health and safety of its workers and the continuity of its business in response to the pandemic.

In the latter half of 2020, the organization strategically advanced the combination of Cenovus with Husky Energy, successfully closing the transaction on January 1, 2021. The combination was the result of extensive due diligence on the part of the leadership team with a high level of governance and oversight by the Board of Directors.

The recommendations and conclusions put forth by Cenovus’s Board while the combination with Husky was being considered were made thoughtfully, with the best interests of shareholders top of mind. We weighed the anticipated benefits and inherent risks of proceeding, conducted a thorough review of the financial health of both companies and carefully analyzed the potential synergies. We also reviewed several alternatives available to Cenovus, including continuing to operate as a standalone entity, and incorporated the advice and assistance of RBC Capital Markets and TD Securities into our decision-making process as we evaluated the transaction.

Going forward, the Board has full confidence in Cenovus’s expanded management team, having established a track record of strong safety performance, operational excellence and cost and capital discipline, along with upstream, downstream and midstream operating expertise. With Cenovus’s enhanced portfolio, we are well positioned for more efficient, returns-focused capital allocation, including opportunities for margin optimization across the business, reduced free funds flow volatility, accelerated net debt reduction and increasing returns to shareholders.

As a result of the Husky combination, the Board renewal process focused on amalgamating the Board of Directors of the combined company. At this time, I would like to formally welcome the

four directors who have joined the Cenovus Board from Husky Energy: Canning Fok, Eva Kwok, Wayne Shaw and Frank Sixt. Each brings a broad range of skills, as well as a deep understanding of Husky’s assets, to complement the expertise of Cenovus’s directors and strengthen the Board’s oversight capabilities. I would also like to recognize and thank Susan Dabarno, Steven Leer and George Lewis, who left Cenovus’s Board upon completion of the transaction, for their excellent and dedicated service to Cenovus.

To enhance their skills and strengthen their understanding of our business environment, we provide continuing education opportunities for all directors. In 2020, this included a virtual environmental, social and governance (ESG) education session presented by external consultants and a virtual reserves workshop presented by Cenovus staff.

Due to the COVID-19 pandemic and the focus on completing the combination with Husky, the Board’s regular shareholder engagement activities were deferred last year. We plan to hold engagement sessions with our largest shareholders in 2021 to gather feedback on Cenovus’s performance, strategy, executive compensation, board renewal and governance practices.

While 2020 was a turbulent year, it was also a critical milestone in the evolution of Cenovus. Today, we are a more diversified, integrated oil and natural gas producer than we were a year ago, with significantly enhanced resilience and financial flexibility to withstand economic volatility as well as improved capacity to generate significant free funds flow. We are also a company focused on being a leader in ESG performance, including our ambition to achieve net zero greenhouse gas emissions by 2050.

While we will no doubt face more challenges in the year ahead, I’m encouraged by the recovery that has taken hold over the last few months. With COVID-19 vaccination programs well underway and improved discipline among OPEC and non-OPEC members to strategically manage global supply, oil prices have strengthened along with other macro-economic factors, increasing the opportunity for stronger financial performance this year.

In closing, I would like to thank all of our stakeholders for their ongoing support and confidence in our company as we continue to execute our strategic vision in 2021 and beyond.

/s/ Keith MacPhail

Board Chair

 

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE YEAR ENDED DECEMBER 31, 2020

 

 

 

 

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy 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) as at December 31, 2020 and, for greater certainty, unless otherwise specified or the context otherwise requires, excludes Husky Energy Inc. (“Husky”) and the subsidiaries of, and partnership interests held by Husky and its subsidiaries, dated February 8, 2021, should be read in conjunction with our December 31, 2020 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”). All of the information and statements contained in this MD&A are made as of February 8, 2021, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (the “Board”) reviewed and recommended the MD&A for approval by the Board, which occurred on February 8, 2021. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.

On January 1, 2021, pursuant to a plan of arrangement under the Business Corporations Act (Alberta), Husky became a wholly-owned subsidiary of Cenovus. In connection with its acquisition of Husky and in accordance with applicable securities laws, Cenovus will be filing a business acquisition report containing the pro forma financial statements of the combined company as of December 31, 2020. Additional information concerning Husky’s business and assets as of December 31, 2020 may be found in the annual information form of Husky dated February 8, 2021 for the year ended December 31, 2020 (the “Husky AIF”) and Husky’s management’s discussion and analysis of the financial and operating results for the year ended December 31, 2020 (the “Husky MD&A”), each of which is filed and available on SEDAR under Husky’s profile at sedar.com.

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 “$”), except where another currency has been indicated, and in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board (“IASB”). Production volumes are presented on a before royalties basis.

Non-GAAP Measures and Additional Subtotals

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow, Operating Earnings, Free Funds Flow, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) and therefore are considered non-GAAP measures. In addition, Operating Margin is considered an additional subtotal found in Note 1 of our Consolidated Financial Statements. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS.

The definition and reconciliation, if applicable, of each non-GAAP measure or additional subtotal is presented in the Operating and Financial Results, Liquidity and Capital Resources sections of this MD&A as well as the Netback Reconciliations on page 132.

 

 

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OVERVIEW OF CENOVUS

 

We are a Canadian-based integrated oil and natural gas company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. At December 31, 2020, prior to the close of the transaction with Husky on January 1, 2021, as described below, our operations included oil sands projects in northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our upstream assets averaged approximately 472,000 BOE per day in 2020. We also conducted marketing activities and have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of 372,000 gross barrels per day of crude oil feedstock into an average of 385,000 gross barrels per day of refined products in 2020.

For a description of our operations in 2020, refer to the Reportable Segments section of this MD&A.

Cenovus and Husky Arrangement

On October 24, 2020, Cenovus and Husky entered into a definitive agreement to combine the two companies in an all-stock transaction to create a resilient Canadian-based integrated energy company. The transaction was accomplished through a plan of arrangement (“the Arrangement”) pursuant to which Cenovus acquired all the issued and outstanding common shares of Husky in exchange for common shares and common share purchase warrants of Cenovus. In addition, all of the issued and outstanding Husky preferred shares were exchanged for Cenovus preferred shares with substantially identical terms. The Arrangement closed on January 1, 2021 and we continue to operate as Cenovus, trade under the Cenovus name, and remain headquartered in Calgary, Alberta.

The Arrangement combines high quality oil sands and heavy oil assets with extensive trading, supply and logistics infrastructure, and downstream infrastructure, creating opportunities to optimize the margin captured across the heavy oil value chain. With the combination of processing capacity and market access outside Alberta for the majority of the Company’s oil sands and heavy oil production, exposure to Alberta heavy oil price differentials is reduced while maintaining exposure to global commodity prices. The combined company has a cost-and-market- advantaged asset portfolio, which prioritizes free funds flow generation, balance sheet strength and returns to shareholders.

The combined company is the third largest Canadian oil and natural gas producer and the second largest Canadian- based refiner and upgrader with operations in Canada, the U.S. and the Asia Pacific region. Our operations include oil sands projects in northern Alberta, thermal and conventional crude oil and natural gas projects across Western Canada, crude oil production offshore Newfoundland and Labrador and natural gas and liquids production offshore China and Indonesia. Our downstream operations include upgrading, refining and marketing operations in Canada and the U.S.

Management is in the process of finalizing the determination of the operating and reporting segments for the Company. It is anticipated that the Company’s business will be conducted predominately through an upstream and downstream segment. Management continues to evaluate how the segments may be presented and will make a final determination during the first quarter of 2021.

The Upstream business is anticipated to be reported as follows:

 

  ·  

Oil Sands, includes the development and production of heavy oil and bitumen in northeast Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise and Tucker oil sands projects, as well as Lloydminster Thermal and Cold and Enhanced Oil Recovery assets.

 

  ·  

Conventional, includes the operations from conventional oil and natural gas production, including processing operations in the Deep Basin and other parts of Western Canada.

 

  ·  

Offshore, includes the offshore operations, exploration and development activities in the Asia Pacific region and Atlantic Canada region.

The Downstream business is anticipated to be reported under the following segments:

 

  ·  

Canadian Manufacturing, includes Cenovus’s owned and operated upgrader and asphalt refinery in Lloydminster, the owned and operated crude-by-rail terminal and two ethanol plants.

 

  ·  

Retail, includes the Canadian retail, commercial and wholesale channels.

 

  ·  

U.S. Manufacturing, includes the U.S. operations of wholly owned refineries in Lima and Superior, the jointly owned Wood River and Borger refineries with operator Phillips 66 and the jointly owned Toledo refinery with BP Products North America Inc. as operator.

 

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Our Strategy

Our strategy remains focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. Our diverse and integrated portfolio will help us to deliver stable cash flow through price cycles while maintaining safe and reliable operations. We remain focused on sustainably growing shareholder returns and reducing Net Debt. The diverse portfolio of projects and other opportunities across our business are expected to allow us to leverage increased economies of scale to better compete in an increasingly consolidated energy industry. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility. We plan to use our capital allocation framework to evaluate disciplined investments in our portfolio against dividends, share repurchases and managing to the optimal debt level while maintaining investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage to generate the highest returns and incorporate Environmental, Social and Governance (“ESG”) considerations into our business plan.

On January 28, 2021 we announced the 2021 budget for the combined company focused on sustaining capital and generating free funds flow to strengthen the balance sheet, accelerated by capturing transaction-related synergies across the organization. 2021 guidance dated January 28, 2021 is available on our website at cenovus.com.

Additional information on the Arrangement is available in our news releases, dated October 25, 2020 and January 4, 2021 available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com, in our joint management information circular with Husky dated November 9, 2020 available on SEDAR and EDGAR, and in our material change reports dated November 3, 2020 and January 11, 2021 available on SEDAR and EDGAR. The information in this MD&A, as it relates to our operations for 2020, does not reflect the closing of the Arrangement, unless otherwise noted.

LOW OIL PRICES AND THE NOVEL CORONAVIRUS (“COVID-19”)

 

 

2020 was a challenging year due to the significant decrease in crude oil demand due to COVID-19 resulting in the low global oil price environment.

During the first half of the year, there was a significant reduction in crude oil demand as a result of measures taken by governments around the world to contain the COVID-19 pandemic. At the same time, overall global crude oil supply increased as efforts between the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC members, primarily Saudi Arabia and Russia, to manage global crude oil production levels broke down and each party increased their daily crude production. The combination of these events resulted in a collapse of crude oil benchmark prices, dropping to a low of US$10.01 per barrel, excluding a historic one-day low of negative US$37.63 per barrel on April 20, 2020.

In light of these unprecedented conditions, we reduced our planned capital investment plan, operating costs, and general and administrative (“G&A”) costs. We remained focused on enhancing our financial resilience and financial capability to maintain our base business and deliver safe and reliable operations.

In April, the agreement between OPEC and a group of 10 non-OPEC members (collectively, “OPEC+”) to cut crude oil output, and several other countries announcing similar production cuts decreased the global supply of crude oil. At the same time, governments began to ease off on some of the measures taken to contain the pandemic increasing demand for crude oil, which helped increase crude oil prices.

In the second half of 2020, crude oil prices improved from the low prices impacting the first half of the year; however, prices continued to be volatile due to market responses to COVID-19 and OPEC crude oil production output decisions. Volatility of crude oil prices continued in the fourth quarter, responding to news of COVID-19 vaccine breakthroughs, continued OPEC and OPEC+ output restrictions, and government responses to the resurgence of COVID-19 cases.

We believe that we have ample liquidity and runway to sustain our operations through a prolonged market downturn. Following the closing of the Arrangement on January 1, 2021, Cenovus has $8.5 billion in committed credit facilities, with $2.0 billion maturing in June 2022, $1.2 billion maturing in November 2022, $3.3 billion maturing in November 2023, and $2.0 billion maturing in March 2024. Under the terms of Cenovus’s committed credit facilities, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement governing the credit facilities, not to exceed 65 percent. As at December 31, 2020, the Company was well below this limit and we expect to continue to be in compliance with all financial covenants under the credit facilities.

The Provincial and Federal governments have recognized the serious economic impacts of COVID-19 and have taken steps to provide various programs, such as the Canada Emergency Wage Subsidy (“CEWS”) program. During the year we continued to benefit from the assistance of the CEWS program to help protect jobs during the pandemic.

The Company remains committed to the health and safety of its workforce and the public while providing essential services. Physical distancing measures continue to be taken to maintain the health and safety of our people and to help mitigate the risk of COVID-19 at our workplaces. We continue to monitor the changing COVID-19 situation and respond accordingly in a timely manner. In October, we lifted our mandatory work from home measure,

 

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implemented in March, to open our modified workspaces in the Calgary offices to staff again, with workplace safety plans and protocols in place. However, due to rising COVID-19 cases in November this was scaled back and office staff are once again required to work from home. Mandatory work-from-home measures are now in place for all non-essential staff at our combined offices and worksites in Alberta, Saskatchewan and Manitoba until the end of March 2021, pending further review. Our U.S. and Atlantic Canada locations will continue to take direction from local health authorities regarding their COVID-19 workplace mandates. Staff levels at sites and offices have and will continue to follow guidance received from the applicable federal, provincial, state and local governments and public health officials.

YEAR IN REVIEW

 

 

During 2020, operating variables under Management’s control performed well. We focused on delivering value through preserving financial resilience. Throughout the year, we demonstrated our ability to use our full suite of assets to maximize prices received for every barrel as we adjusted our Oil Sands production rates in response to price signals and stored volumes in a low-price environment and cleared inventory when we could obtain higher prices. We also remained focused on maintaining our low cost structure.

Operationally, our upstream assets performed well. Our upstream production averaged 471,740 BOE per day in 2020, compared with 451,680 BOE per day in 2019. In 2020 we managed our production to optimal levels, producing above the Government of Alberta’s mandatory production curtailment as we purchased additional credits. As of December 2020, monthly oil production limits are no longer in effect and the Government of Alberta will give 30 to 60 days’ notice if production limits are put back into place.

The Wood River and Borger refineries (the “Refineries”) demonstrated reliable operational performance while operating below capacity for the majority of the year due to economic crude rate reductions in response to lower refined product demand and weak market crack spreads.

Throughout 2020, Management continued to focus on maintaining our low operating and capital cost structure.

Crude oil prices were volatile throughout the year due to demand and supply impacts as a result of COVID-19 and OPEC and non-OPEC members production level commitments. West Texas Intermediate (“WTI”) benchmark crude oil prices ranged from a high of US$63.27 per barrel to a low of US$10.01 per barrel and averaged 31 percent lower than 2019. Western Canadian Select (“WCS”) benchmark prices averaged US$26.80 per barrel, 39 percent lower than US$44.27 per barrel in 2019. Our average realized crude oil sales price of $28.82 per barrel decreased significantly compared with $53.95 per barrel in 2019 due to declining benchmark WTI prices.

As noted, COVID-19 had a significant impact on our results.

 

·  

Our first quarter results were impacted by measures taken to contain COVID-19 and the over-supply of crude oil. We responded by announcing reductions to our capital spending, operating and G&A costs, and temporarily suspended our dividend. Average WTI and WCS crude oil benchmark prices for the first quarter declined to US$46.17 per barrel and US$25.64 per barrel, respectively, which had a significant impact on our first quarter results with asset impairment charges of $318 million, a Net Loss of $1,797 million and our operating margin was negative $589 million;

·  

The second quarter was a transition period for the market. Crude oil prices were severely impacted, with WCS averaging a low of US$3.50 per barrel in April. This was followed by a steady strengthening of crude oil prices with WCS averaging US$33.97 per barrel in June, caused by the easing of some of the restrictions imposed by governments to limit the spread of COVID-19 combined with the commitment by OPEC and non-OPEC members to reduce crude oil production levels in response to lower demand and low commodity prices. We responded to price signals, managing our Oil Sands production by reducing production rates in April and successfully ramped up production in May and June, to achieve peak production rates, when pricing was more favourable. Our Net Loss of $235 million improved in the second quarter compared with the first quarter and our operating margin was $291 million, demonstrating some momentum in economic recovery;

·  

Our results in the third quarter gradually improved along with the improvement in crude oil prices. WTI and WCS averaged US$40.93 per barrel and US$31.84 per barrel, respectively, in the third quarter. However, crude oil prices remained low as the second wave of COVID-19 infections drove uncertainty. Operationally, our upstream assets continued to perform well and in response to increasing crude oil prices, we purchased production curtailment credits available in the market to produce above our curtailment limit and sold crude oil inventory that had built up when crude oil prices were lower. Our Net Loss of $194 million, which included impairments and write-downs of $521 million, continued to improve quarter over quarter and operating margin of $594 million more than doubled that of the second quarter of 2020. In the third quarter we used the proceeds from the issuance of US$1.0 billion in 5.375 percent senior unsecured notes due in 2025 to repay short-term borrowings; and

·  

Our fourth quarter results were mixed as COVID-19 infection rates, global economic performance and speculation on vaccine development impacted the pace of crude oil demand recovery with WTI and WCS averaging US$42.66 per barrel and US$33.36 per barrel, respectively. Our fourth quarter Net Loss of $153 million decreased and operating margin of $625 million increased compared with the third quarter of

 

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2020, and we recognized $298 million in impairments and write-downs. Net income also included a $100 million loss related to the Keystone XL pipeline project. We exited the year with Net Debt of $7.2 billion.

In 2020, upstream operating margin of $1,309 million decreased compared with $3,723 million in 2019, due to a lower average realized crude oil sales price, the use of higher priced condensate in a declining market earlier in the year, partially offset by lower royalties and higher sales volumes.

Our Refining and Marketing segment generated operating margin of negative $388 million, down from $737 million in 2019 primarily due to decreased market crack spreads, lower crude advantage and reduced crude oil runs, partially offset by lower operating costs.

OPERATING AND FINANCIAL RESULTS

 

Selected Operating Results

 

      2020             Percent
Change		             2019             Percent
Change		             2018  

Upstream Production Volumes

                       

Oil Sands (barrels per day)

                       

Foster Creek

      163,210          2          159,598          (1 )         161,979  

Christina Lake

      218,513          12          194,659          (3 )         201,017  

Total Oil Sands Crude Oil

      381,723          8          354,257          (2 )         362,996  

Conventional (1) (BOE per day)

      89,932          (8 )         97,423          (19 )            120,258  

Total Production from Continuing Operations (BOE per day)

         471,740          4          451,680          (7 )         483,458  

Production From Discontinued Operations (BOE per day)

      -          -          -          (100 )         294  

Sales from Continuing Operations (2) (BOE per day)

      420,456                        8          390,813          (10 )         436,163  

Oil and Gas Reserves (MMBOE)

                                

Proved

      5,030          (1 )         5,103          (1 )         5,167  

Probable

      1,656          (6 )         1,768          (3 )         1,821  

Proved plus Probable

      6,686          (3 )         6,871          (2 )         6,988  
                                                    

Refining and Marketing

                       

Crude Oil Runs (3) (Mbbls/d)

      372          (16 )         443          (1 )         446  

Refined Product (3) (Mbbls/d)

      385          (17 )         466          (1 )         470  

Crude Utilization (3) (percent)

      75          (17 )         92          (5 )         97  

Crude-by-Rail (barrels per day)

                       

Crude-by-Rail Loads (4)

      30,422          (43 )         53,345          1,197          4,113  

Crude-by-Rail Sales (5)

      33,870                (30 )                    48,626                       1,367                3, 314  

 

(1)

This segment was previously referred to as the Deep Basin segment.

(2)

Less natural gas volumes used for internal consumption by the Oil Sands segment.

(3)

Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.

(4)

Represents volumes transported outside of Alberta.

(5)

Represents volumes sold outside of Alberta.

Upstream Production Volumes

Oil Sands production for 2020 reflects production above our curtailment limit as we managed to optimal production levels by purchasing production curtailment credits. In 2019, our production was in line with the Government of Alberta’s mandatory production curtailment program and impacted by a planned turnaround at Christina Lake during the second quarter of 2019.

Conventional production in 2020 decreased to 89,932 BOE per day compared with 97,423 BOE per day in 2019, due to natural declines, partially offset by Marten Hills heavy oil production prior to its disposition, as well as fewer shut-ins for low commodity pricing. Prior to the disposition, Marten Hills production averaged approximately 2,800 barrels per day.

Oil and Gas Reserves

Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2020 we had total proved reserves and total proved plus probable reserves of approximately 5.0 billion BOE and 6.7 billion BOE, respectively, decreases of one percent and three percent compared with 2019. As a result of the close of the Arrangement on January 1, 2021, including reported reserves from Husky, our total proved reserves

 

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and total proved plus probable reserves are anticipated to increase by approximately 1.2 billion BOE and 1.8 billion BOE, respectively.

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 decreased in 2020 as both Refineries implemented crude rate reductions in response to reduced demand as a result of COVID-19. The economic crude rate reductions in 2020 had a greater impact than the operational performance impacts from unplanned outages, planned maintenance and turnaround activities at the Refineries in 2019.

Further information 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 Statements.

Selected Consolidated Financial Results

Market factors such as falling crude oil prices, low market crack spreads, and volatile blending costs were the primary drivers of our financial results. The following key performance measures are discussed in more detail within this MD&A.

 

($ millions, except per share amounts)    2020             Percent
Change		     2019      Percent
Change		     2018 (1)  

Operating Margin (2) (3)

      921          (79 )      4,460        86       2,394  

Cash From (Used in) Operating Activities

               

From Continuing Operations

      273          (92 )      3,285        55       2,118  

Total

      273          (92 )      3,285        53       2,154  

Adjusted Funds Flow (4)

      147          (96 )      3,702        115       1,721  

Operating Earnings (loss) (2) (4)

      (2,604 )         (671 )      456        117       (2,755 ) 

Per Share ($) (5)

      (2.12 )         (673 )      0.37        117       (2.24 ) 

Net Earnings (Loss)

               

From Continuing Operations

      (2,379 )         (208 )      2,194                  175       (2,916 ) 

Per Share ($) (5)

      (1.94 )         (209 )      1.78        175       (2.37 ) 

Total

      (2,379 )         (208 )      2,194        182       (2,669 ) 

Per Share ($) (5)

      (1.94 )         (209 )      1.78        182       (2.17 ) 

Total Assets

           32,770          (7 )           35,173        -       35,174  

Total Long-Term Financial Liabilities (6)

      9,041                        7       8,483        (1 )      8,602  

Capital Investment (7)

      841          (28 )      1,176        (14 )      1,363  

Dividends

                        

Cash Dividends

      77          (70 )      260        6       245  

Per Share ($)

      0.0625                (71 )      0.2125        6              0.2000  
(1)

On January 1, 2019, we adopted IFRS 16, “Leases” (“IFRS 16”), 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 our 2019 annual MD&A.

(2)

Represented on a continuing basis.

(3)

Additional subtotal found in Note 1 of the Consolidated Financial Statements and defined in this MD&A.

(4)

Non-GAAP measure defined in this MD&A. The comparative periods have been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals.

(5)

Represented on a basic and diluted per share basis.

(6)

Includes Long-Term Debt, Lease Liabilities, Contingent Payment Liabilities and other financial liabilities included within Other Liabilities on the Consolidated Balance Sheets.

(7)

Includes expenditures on property, plant and equipment (“PP&E”) and Exploration and Evaluation (“E&E”) assets.

 

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Operating Margin

Operating Margin is an additional subtotal found in Note 1 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, inventory write-downs, net of reversals, 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)                                2020                              2019 (1) (2)                                    2018 (2)  

Gross Sales

   14,200       22,042         22,113  

Less: Royalties

   364       1,173         546  
                       

Revenues

   13,836       20,869         21,567  

Expenses

          

Purchased Product

   5,397       8,795         9,201  

Transportation and Blending

   4,480       5,234         5,969  

Operating Expenses

   2,236       2,324         2,367  

Inventory Write-Down (Reversal)

   555       49         60  

Realized (Gain) Loss on Risk Management Activities

   247       7         1,576  
                       

Operating Margin

   921       4,460         2,394  
                       

 

(1)

The comparative period has been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals.

(2)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

Operating Margin Variance

 

LOGO

 

(1)

Other includes the net effect of 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 decreased in 2020 primarily due to:

 

·  

A 47 percent decline in our average crude oil sales price resulting from lower WTI and WCS benchmark pricing;

·  

Lower Operating Margin from our Refining and Marketing segment primarily due to reduced market crack spreads, lower crude advantage and reduced crude oil runs, partially offset by lower operating costs; and

·  

The use of higher priced condensate in a declining market earlier in the year.

These decreases in Operating Margin were partially offset by:

 

·  

Lower royalties due to lower realized prices;

·  

Higher liquids sales volumes; and

·  

A decrease in transportation and blending expenses due to lower priced condensate used for blending.

Additional details explaining the changes in Operating Margin can be found in the Reportable Segments section of this MD&A.

Cash From (Used in) Operating Activities and Adjusted Funds Flow

Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as cash from (used in) operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable, inventories (excluding non-cash inventory write-downs and reversals), 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.

 

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($ millions)                       2020                                2019                                2018 (1)  

Cash From (Used in) Operating Activities

     273         3,285         2,154  

(Add) Deduct:

          

Net Change in Other Assets and Liabilities

     (72 )        (84 )        (72 ) 

Net Change in Non-Cash Working Capital (2)

     198         (333 )        505  
                           

Adjusted Funds Flow (2)

     147         3,702         1,721  
                           

 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

(2)

The comparative period has been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals.

Cash From Operating Activities and Adjusted Funds Flow decreased significantly in 2020, primarily due to lower Operating Margin, as discussed above, transaction costs of $29 million related to the Arrangement, and higher finance costs. The decrease was partially offset by funding from the CEWS program and a current tax recovery of $13 million compared with current tax expense of $17 million. Adjusted Funds Flow was further reduced by a $100 million loss related to the Keystone XL pipeline project. The change in non-cash working capital in 2020 was primarily due to a decrease in inventory and accounts receivable, partially offset by a decrease in accounts payable.

In 2019, the change in non-cash working capital 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.

Operating Earnings (Loss)

Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before income tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.

 

($ millions)                       2020                                2019                                2018 (1)  

Earnings (Loss), Before Income Tax

     (3,230 )        1,397         (3,926 ) 

Add (Deduct):

          

Unrealized Risk Management (Gain) Loss (2)

     56         149         (1,249 ) 

Non-Operating Unrealized Foreign Exchange (Gain) Loss (3)

     (194 )        (787 )        593  

(Gain) Loss on Divestiture of Assets

     (81 )        (2 )        795  

Operating Earnings (Loss), Before Income Tax

     (3,449 )        757         (3,787 ) 

Income Tax Expense (Recovery)

     (845 )        301         (1,032 ) 
                           

Total Operating Earnings (Loss)

     (2,604 )        456         (2,755 ) 
                           

 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

(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 transactions.

We incurred an Operating Loss in 2020, relative to Operating Earnings in 2019, primarily due to lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above, higher Depletion, Depreciation and Amortization (“DD&A”) including impairment charges of $1,112 million, and operating unrealized foreign exchange losses of $63 million compared with gains of $27 million in 2019. The increase in our Operating Loss was partially offset by non-operating realized foreign exchange gains of $33 million compared with realized losses of $401 million in 2019 on our unsecured notes, a re-measurement gain of $80 million on the contingent payment compared with a loss of $164 million in 2019, and lower non-cash employee long-term incentive costs.

 

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Net Earnings (Loss)

 

($ millions)  

                    2020

vs. 2019

         

                    2019

vs. 2018(1)

  

Net Earnings (Loss), Comparative Year

     2,194         (2,916 ) 

Increase (Decrease) due to:

      

Operating Margin

     (3,539 )        2,066  

Corporate and Eliminations:

      

Unrealized Risk Management Gain (Loss)

     93         (1,398 ) 

Unrealized Foreign Exchange Gain (Loss)

     (696 )        1,476  

Re-measurement of Contingent Payment

     244         (114 ) 

Gain (Loss) on Divestiture of Assets

     79         797  

Expenses (2)

     416         573  

DD&A

     (1,215 )        (118 ) 

Exploration Expense

     (9 )        2,041  

Income Tax Recovery (Expense)

     54         (213 ) 
                 

Net Earnings (Loss), End of Year

     (2,379 )        2,194  
                 

 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

(2)

Includes Corporate and Eliminations realized risk management (gains) losses, general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, research costs, other (income) loss, net, Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses.

Net Loss of $2,379 million was significantly lower than Net Earnings of $2,194 million in 2019 due to lower Operating Earnings, as discussed above, and non-operating unrealized foreign exchange gains of $194 million compared with $787 million in 2019 partially offset by unrealized risk management losses of $56 million in 2020 compared with losses of $149 million in 2019 and a gain of $79 million on the divestiture of the Marten Hills assets.

Capital Investment

 

($ millions)                           2020                                2019 (1)                                2018 (2)  

Oil Sands

     427         656         870  

Conventional (3)

     78         103         228  

Refining and Marketing

     276         280         208  

Corporate and Eliminations

     60         137         57  
                           

Capital Investment (4)

     841         1,176         1,363  
                           

 

(1)

In the first quarter of 2020, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment, prior to the divestiture in December 2020. The comparative information has been reclassified.

(2)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

(3)

This segment was previously referred to as the Deep Basin segment.

(4)

Includes expenditures on PP&E and E&E assets.

Capital investment in 2020 decreased compared with 2019, reflecting our reduced capital investment program and revised budget announced in April. Our upstream capital investment focused primarily on sustaining programs. Our downstream capital expenditures focused primarily on yield enhancement, reliability and maintenance projects, as well as storage infrastructure projects.

Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.

 

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COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

 

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 following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.

Selected Benchmark Prices and Exchange Rates (1)

 

(US$/bbl, unless otherwise indicated)   Q4 2020     Q4 2019     2020           

Percent

Change

     2019     2018  

Brent

              

Average

           45.24             62.50             43.21                 (33 )            64.18             71.53  

WTI

              

Average

     42.66       56.96       39.40         (31 )      57.03       64.77  

Average Differential Brent-WTI

     2.58       5.54       3.81         (47 )      7.15       6.76  

WCS at Hardisty (“WCS”)

              

Average

     33.36       41.13       26. 80         (39 )      44.27       38.46  

Average Differential WTI-WCS

     9.30       15.83       12.60         (1 )      12.76       26.31  

Average (C$/bbl)

     43.41       54.29       35.59         (39 )      58.77       49.81  

WCS at Nederland

              

Average

     40.36       51.47       35.86         (35 )      55.56       62.05  

Average Differential WTI-WCS at Nederland

     2.30       5.49       3.54         141       1.47       2.72  

West Texas Sour (“WTS”)

              

Average

     43.02       57.26       39.37         (30 )      56.27       57.24  

Average Differential WTI-WTS

     (0.36 )      (0.30 )      0.03         (96 )      0.76       7.53  

Condensate (C5 @ Edmonton)

              

Average

     42.54       53.01       37.16         (30 )      52.86       61.00  

Average Differential WTI-Condensate (Premium)/Discount

     0.12       3.95       2.24         (46 )      4.17       3.77  

Average Differential WCS-Condensate (Premium)/Discount

     (9.18 )      (11.88 )      (10.36 )        21       (8.59 )      (22.54 ) 

Average (C$/bbl)

     55.36       69.97       49.44         (30 )      70.15       79.02  

Average Refined Product Prices

              

Chicago Regular Unleaded Gasoline (“RUL”)

     47.31       64.83       45.24         (36 )      70.55       77.96  

Chicago Ultra-low Sulphur Diesel (“ULSD”)

     54.21       78.09       50.08         (36 )      77.97       86.75  

Refining Margin: Average 3-2-1 Crack

              

Spreads (2)

              

Chicago

     7 .05       12.27       7.54         (53 )      16.00       15.97  

Group 3

     7.57       14.60       8.67         (48 )      16.67       16.74  

Average Natural Gas Prices

              

AECO (3) (C$/Mcf)

     2.77       2.34       2.24         38       1.62       1.53  

NYMEX (US$/Mcf)

     2.66       2.50       2.08         (21 )      2.63       3.09  

Foreign Exchange Rate (US$ per C$1)

              

Average

     0.768       0.758       0.746         (1 )      0.754       0.772  

End of Period

     0.785       0.770       0.785               2       0.770       0.733  

 

(1)

These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management results, refer to the Netback tables in the Reportable Segments section 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 and Condensate Benchmarks

In 2020, the demand for crude oil was under pressure due to COVID-19 while OPEC-led production cuts reduced the impact of the demand destruction resulting in lower average Brent and WTI crude oil benchmark prices.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In 2020, the Brent-WTI differential narrowed compared with 2019 due to lower exports of crude oil from North America and reduced U.S. crude oil supply.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. In 2020, the WTI-WCS at Hardisty differential narrowed slightly compared with 2019 as reduced Western Canadian Sedimentary Basin (“WCSB”) crude supply resulted in excess pipeline capacity for parts of the year, reducing the need for more expensive crude-by-rail shipments. This resulted in average differentials being similar to 2019 when the Government of Alberta enforced their mandatory production curtailment limits.

 

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WCS at Nederland is a heavy oil benchmark at the U.S. Gulf Coast (“USGC”) which is representative of pricing for our sales in the USGC. WCS at Nederland crude oil prices weakened in 2020, consistent with falling crude oil prices globally as refiners lowered crude runs to adjust to reduced demand for products. In 2020, WCS at Nederland benchmark prices relative to WTI widened compared with 2019. The widening was mainly attributed to very wide differentials in the second quarter of 2020 when demand was weak and OPEC+ had not yet committed to production cuts. OPEC+ production cuts are weighed towards medium and heavy sour grades and have resulted in narrower heavy differentials at the USGC in the second half of 2020 compared with the same period of 2019.

 

 

LOGO

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 average differential between WTI and WTS benchmark prices narrowed in 2020 as debottlenecking of transportation constraints resulted in WTS trading in a narrow range around parity with WTI pricing since early 2019.

Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent volumes as a percentage of total blended volumes, range from approximately 25 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a wider differential generally results in a decrease in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending as well as timing of sales of blended product.

Average condensate benchmark prices were at a narrower discount relative to WTI in Alberta in 2020 as a result of weaker diluent demand due to shut-in heavy oil production offset by lower imported barrels from the U.S. and strong global demand.

Refining Benchmarks

The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis.

Average Chicago refined product prices decreased in 2020, primarily due to lower refined product demand as a result of COVID-19. Weaker refined product demand resulted in higher inventory levels which put pressure on market crack spreads. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by global prices, the weakening of refining market crack spreads in the U.S. Midwest and Midcontinent will reflect the differential 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 is valued on a first in, first out (“FIFO”) accounting basis.

 

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LOGO

Natural Gas Benchmarks

Average AECO prices strengthened in 2020 compared with 2019 as the differential between AECO and NYMEX narrowed significantly due to lower than expected supply, ample access to domestic storage injections and lower pipeline utilization in the WCSB. Average NYMEX prices decreased compared with 2019 due to lower demand and a large decrease in liquified natural gas exports.

Foreign Exchange Benchmark

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian dollar weakens, there is a positive impact on our reported results. In addition to our revenues being denominated in U.S. dollars, our long-term debt is also U.S. dollar denominated. In periods of a weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars.

The Canadian dollar on average weakened relative to the U.S. dollar in 2020, compared with 2019, resulting in a positive impact of approximately $140 million on our revenues in 2020. The strengthening of the Canadian dollar relative to the U.S. dollar as at December 31, 2020 compared with December 31, 2019, resulted in unrealized foreign exchange gains of $194 million on the translation of our U.S. dollar debt.

REPORTABLE SEGMENTS

 

Our reportable segments at December 31, 2020 are:

Oil Sands, which includes the development and production of bitumen in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development.

Conventional, which includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas in Alberta and British Columbia and the exploration for heavy oil in the Marten Hills area. The assets include interests in numerous natural gas processing facilities. We renamed our Deep Basin segment to Conventional in 2020 and our new resource play, Marten Hills, was reclassified from the Oil Sands segment to the Conventional segment. Comparative periods have been reclassified. On December 2, 2020, we completed the sale of our Marten Hills assets with a retained Gross Overriding Royalty agreement.

Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification.

Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices.

 

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Revenues by Reportable Segment

 

($ millions)                       2020                                2019                                    2018  

Oil Sands

     7,190         9,695         9,553  

Conventional (1)

     595         661         831  

Refining and Marketing

     6,051         10,513         11,183  

Corporate and Eliminations

     (609 )        (689 )        (724 ) 
                           
    13,227         20,180         20,843  
                           
(1)

This segment was previously referred to as the Deep Basin segment.

Oil Sands revenues decreased due to lower average realized liquids sales prices, partially offset by lower royalties and higher sales volumes.

Conventional revenues decreased due to lower average realized liquids sales prices, lower natural gas sales volumes and higher royalties, partially offset by a higher average natural gas sales price and the commencement of heavy oil production from our Marten Hills assets prior to its divestiture.

Refining and Marketing revenues declined in 2020. Refining revenues decreased due to lower refined product pricing consistent with the decline in average refined product benchmark prices and lower refined product output due to the economic crude rate reductions. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group decreased compared with 2019 due to lower crude oil prices and lower volumes, partially offset by higher natural gas prices.

Corporate and Eliminations revenues relate to sales of natural gas or crude oil and operating revenues between segments and are recorded at transfer prices based on current market prices.

Overall, revenues declined slightly in 2019 compared with 2018, primarily due to lower refined product pricing and lower upstream sales volumes, partially offset by higher realized crude oil pricing.

OIL SANDS

In 2020, we:

 

·  

Delivered safe and reliable operations;

·  

Increased our Oil Sands production rates to average 381,723 barrels per day;

·  

Demonstrated our ability to use our full suite of assets to maximize prices received for every barrel as we managed to store volumes in a low-price environment and cleared inventory when we could obtain higher prices; and

·  

Generated Operating Margin of $1,113 million, a decrease of $2,368 million compared with 2019 due to lower average realized sales prices, partially offset by lower royalties, higher volumes and lower transportation and blending costs.

Financial Results

 

($ millions)                       2020                                2019                                2018 (1)  

Gross Sales

     7,514         10,838         10,026  

Less: Royalties

     324         1,143         473  
                           

Revenues

     7,190         9,695         9,553  

Expenses

          

Transportation and Blending

     4,399         5,152         5,879  

Operating

     1,094         1,039         1,037  

Inventory Write-Down (Reversal)

     316         -         -  

(Gain) Loss on Risk Management

     268         23         1,551  

Operating Margin

     1,113         3,481         1,086  

Depreciation, Depletion and Amortization

     1,684         1,543         1,439  

Exploration Expense

     9         18         6  
                           

Segment Income (Loss)

     (580 )        1,920         (359 ) 
                           

 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

 

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Operating Margin Variance

 

LOGO

 

(1)

Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases.

Revenues

Price

In 2020, our realized crude oil sales price was $28.64 per barrel compared with $53.78 per barrel in 2019, consistent with the overall declines in crude oil benchmark pricing led by a decrease in WTI average benchmark price, partially offset by the lower cost of condensate with an average price of US$37.16 per barrel (2019 – US$52.86 per barrel). The decrease in our crude oil price also reflects the wider WCS-Condensate premium of US$10.36 per barrel (2019 – premium of US$8.59 per barrel). In 2020, COVID-19 impacts resulted in low WTI-WCS differentials during periods of the year resulting in more volumes sold in Alberta compared with 2019, which decreased our realized sales prices. In 2019, we sold more than 25 percent of our production at sales locations outside of Alberta. We used our transportation, storage and logistics assets and expertise to sell our products in higher-priced months, when the opportunities were available, which reduced the impact of the drop in crude oil prices on our realized sales prices.

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. 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 relative to the price of blended crude oil, our realized 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 transportation between market hubs and transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to when we sell our blended production. In a declining crude oil price environment, we expect to see a negative impact on our realized bitumen sales price as we are using condensate purchased at a higher price earlier in the year. During the year we reduced condensate volumes transported from the USGC, as the price differential between market hubs was not significant enough to cover variable transportation costs for part of the year. Condensate prices declined during the summer months due to lower demand making it more cost-effective to buy in Alberta compared with the USGC.

As a result of our decisions to store rather than sell, we were able to minimize the impact on our realized sales prices. Cenovus uses its marketing and transportation initiatives, including storage and pipeline assets to optimize product mix, delivery points, transportation commitments and customer diversification, to inventory physical positions. At the time we make the decision to store crude oil and condensate volumes, the prices available for future periods we plan to sell in can be locked in and the improved margin realized in the future periods, which are superior to short-term prices. The additional revenues generated from the underlying physical sales may be impacted by the related risk management gains and losses.

Transactions typically span across periods in order to execute the optimization strategy and these transactions reside across both realized and unrealized risk management. As the financial contracts settle, they will flow from unrealized to realized risk management gains and losses and final settlement will match when the physical product is sold.

Production Volumes

 

(barrels per day)   2020           

Percent

Change

            2019           

Percent

Change

            2018  

Foster Creek

     163,210         2         159,598         (1 )        161,979  

Christina Lake

     218,513         12         194,659         (3 )        201,017  
                                               
        381,723                         8               354,257                         (2 )            362,996  
                                               

 

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In 2020, we actively managed production levels to respond to price signals and the availability of production curtailment credits, both our own and those available in the market. In 2019, our production was in line with Government of Alberta’s mandatory production curtailment program.

Royalties

Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.

Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.

Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one 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 royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). For royalty purposes, gross revenues are a function of sales revenues less diluent costs and transportation costs and net profits are a function of sales revenues less diluent costs, transportation costs, and allowed operating and capital costs.

Foster Creek and Christina Lake are post-payout projects for determining royalties.

Effective Royalty Rates

 

(percent)                2020                  2019                  2018  

Foster Creek

      7.9        18.8        18.0  

Christina Lake

      14.4        21.6        4.8  

In 2020, royalties decreased $819 million compared with 2019 as a result of lower net profits due to lower commodity pricing, combined with lower Alberta Department of Energy posted royalty rates related to decreased annual average WTI benchmark pricing.

Expenses

Transportation and Blending

Total transportation and blending costs have decreased $753 million compared with 2019. Blending costs decreased due to a decline in condensate price, partially offset by increased condensate volumes required to move increased bitumen volumes.

Transportation costs increased primarily due to higher fixed costs in 2020, as our rail freight and offloading commitments gradually increased in 2019 as the crude-by-rail program ramped up.

Per-unit Transportation Expenses

Foster Creek per-barrel transportation costs decreased $0.65 per barrel due to lower pipeline tariffs as a result of lower sales at U.S. destinations and increased sales volumes, partially offset by increased rail transportation costs from higher fixed costs in 2020, as discussed above. Christina Lake per-barrel transportation costs increased $0.31 per barrel as a result of increased pipelines tariff rates due to higher piped sales at U.S. destinations, higher fixed costs, as discussed above, and higher storage costs, partially offset by increased sales volumes relative to 2019.

Operating

Total operating costs increased $55 million due to higher fuel, workforce, and chemical costs from increased production, partially offset by lower repairs and maintenance costs and fluid, waste handling and trucking costs from the 2020 planned turnaround compared with the planned turnaround at Christina Lake in the second quarter of 2019 and reduction in activity and resources due to COVID-19 safety measures.

Per-unit Operating Expenses

 

($/bbl)               2020           

            Percent

Change

                        2019           

            Percent

Change

                      2018 (1)  

Foster Creek

                  

Fuel

     2.83         15         2.47         16         2.13  

Non-fuel

     6.41         (4 )        6.67         (2 )        6.84  
                                               

Total

     9.24         1         9.14         2         8.97  
                                               

Christina Lake

                  

Fuel

     2.18         6         2.06         10         1.87  

Non-fuel

     4.61         (13 )        5.27         11         4.73  
                                               

Total

     6.79         (7 )        7.33         11         6.60  
                                               

Total

     7.84         (4 )        8.15         7         7.65  
                                               

 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

 

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At both Foster Creek and Christina Lake, per-barrel fuel costs increased due to higher natural gas prices and consumption, partially offset by higher sales volumes.

Per-barrel non-fuel operating expenses at Foster Creek decreased in 2020 primarily due to higher sales volumes and COVID-19 safety measures implemented in the second quarter resulting in less repairs and maintenance activity, partially offset by higher workforce costs.

Per-barrel non-fuel operating expenses at Christina Lake decreased in 2020 primarily due to higher sales volumes, and lower costs for the 2020 planned turnaround compared with costs for the planned turnaround in 2019, partially offset by higher workforce and chemical costs.

Netbacks (1)

Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Our Netback calculation is aligned with the definition found 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 and operating expenses divided by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when 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 Netbacks see the Advisory section of this MD&A.

 

    Foster Creek           Christina Lake  
($/bbl)           2020 (2)                    2019                    2018                    2020 (2)                    2019                    2018  

Sales Price

     30.80         57.21         42.63         27.04         50.91         33.42  

Royalties

     1.57         8.44         6.25         2.90         9.42         1.37  

Transportation and Blending

     11.05         11.70         8.34         6.95         6.64         5.25  

Operating Expenses

     9.24         9.14         8.97         6.79         7.33         6.60  
                                                         

Netback Excluding Realized Risk Management

     8.94         27.93         19.07         10.40         27.52         20.20  

Realized Risk Management Gain (Loss)

     (1.83 )        (0.16 )        (11.49 )        (1.93 )        (0.19 )        (11.66 ) 
                                                         

Netback Including Realized Risk Management

     7.11         27.77         7.58         8.47         27.33         8.54  
                                                         

 

(1)

Netbacks reflect our margin on a per-barrel basis of unblended crude oil.

(2)

The netbacks do not reflect non-cash write-downs or reversals of product inventory.

Our average Netback, excluding realized risk management gains and losses, decreased in 2020 compared with 2019, primarily due to lower realized sales prices, partially offset by lower royalties, operating costs and transportation and blending costs, and higher sales volumes. The weakening of the Canadian dollar relative to the U.S. dollar compared with 2019 had a positive impact on our overall reported sales price of approximately $0.30 per barrel.

DD&A

We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The unit-of-production rate accounts for expenditures incurred 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 each period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves.

In 2020, DD&A increased $141 million compared with 2019, due to higher sales volumes, partially offset by a decrease in our average depletion rates. Our depletion rate decreased due to lower future development costs and a decrease in maintenance capital. The average depletion rate for the year ended December 31, 2020 was approximately $10.40 per barrel (2019 – $11.15 per barrel).

We depreciate our right-of-use (“ROU”) assets on a straight-line basis over the shorter of the estimated useful life or the lease term.

Capital Investment

 

($ millions)                       2020                                2019                                2018 (1)  

Foster Creek

     193         243         379  

Christina Lake

     162         362         445  
                           
    355         605         824  

Other (2)

     72         51         46  
                           

Capital Investment (3)

     427         656         870  
                           

 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

(2)

Includes Narrows Lake and new resource plays. In Q1 2020, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified.

(3)

Includes expenditures on PP&E and E&E assets.

 

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In 2020, Oil Sands capital investment focused on sustaining programs related to existing production at Foster Creek and Christina Lake as well as the stratigraphic test well program. Other capital investment related to advancing key initiatives and technology development costs. In 2019, capital investment primarily related to sustaining and stratigraphic test well programs and the completion of Christina Lake phase G construction.

Drilling Activity

 

     Gross Stratigraphic
Test Wells		     

Gross Production

Wells(1)

     

 

          
      2020             2019             2018             2020             2019              2018  

Foster Creek

      38          14          43          -          -           14  

Christina Lake

      42          18          63          -          11           38  
     80          32          106          -          11           52  

Other (2)

     75          26          20          -          -           -  
                     155                          58                      126                              -                          11                           52  
                                                                

 

(1) 

Steam-assisted gravity drainage (“SAGD”) well pairs are counted as a single producing well.

(2) 

Includes Narrows Lake and new resource plays. In Q1 2020, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified.

Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and future expansion phases, and to further progress the evaluation of emerging assets. In 2020, we increased the number of gross stratigraphic test wells drilled by increasing the scope of the program and incorporating more multi-leg wells, which have a reduced surface impact.

CONVENTIONAL

In 2020, we:

 

·  

Produced a total of 89,932 BOE per day, down from 2019 due to natural declines partially offset by added production from the Marten Hills area, prior to its divestiture on December 2, 2020;

·  

Generated Operating Margin of $196 million, a decrease from 2019 due to reduced sales volumes, lower realized prices, and higher royalties, partially offset by lower operating costs;

·  

Reduced operating costs by approximately six percent to $318 million compared with $337 million in 2019, by optimizing operations, focusing on critical repairs and maintenance activities and leveraging our infrastructure;

·  

Earned a Netback of $5.16 per BOE; and

·  

Divested our Marten Hills assets and entered into a Gross Overriding Royalty agreement and an equity position in the purchaser to benefit from its future development.

Financial Results

 

($ millions)    2020             2019             2018 (1)  

Gross Sales

      635          691          904  

Less: Royalties

      40          30          73  

Revenues

      595          661          831  

Expenses

             

Transportation and Blending

      81          82          90  

Operating

      318          337          403  

(Gain) Loss on Risk Management

      -          -          26  

Operating Margin

      196                              242                              312  

Depreciation, Depletion and Amortization

                          880          319          412  

Exploration Expense

      82          64          2,117  

Segment Income (Loss)

      (766 )         (141 )         (2,217 ) 
                              

 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

 

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Operating Margin Variance

 

LOGO

Revenues

Price

 

      2020      2019      2018  

Heavy Oil ($/bbl)

      31.45        -        -  

Light and Medium Oil ($/bbl)

      42.78        65.70        66.71  

NGLs ($/bbl)

      22.04        26.36        38.56  

Natural Gas ($/mcf)

      2.37        2.01        1.72  

Total Oil Equivalent ($/BOE)

                          17.84                            17.95                            19.31  

For the year ended December 31, 2020, revenues declined due to decreased average realized liquids sales prices and lower natural gas sales volumes, partially offset by higher natural gas sales prices and liquids sales volumes. In 2020, prior to its divestiture, we had heavy oil production from Marten Hills of approximately 2,700 barrels per day. In 2020, revenues included $49 million of processing fee revenue related to our interests in natural gas processing facilities (2019 – $53 million). We do not include processing fee revenue in our per-unit pricing metrics or our Netbacks.

Production Volumes

 

      2020             2019             2018  

Liquids

             

Crude Oil (barrels per day)

      7,244          4,911          5,916  

NGLs (barrels per day)

      19,513          21,762          26,538  
     26,757          26,673          32,454  

Natural Gas (MMcf per day)

      379          424          527  

Total Production (BOE/d)

                        89,932                      97,423                      120,258  
                              

Natural Gas Production (percentage of total)

      70          73          73  

Liquids Production (percentage of total)

      30                27                27  

Production in 2020 decreased due to natural declines, partially offset by Marten Hills heavy oil production, prior to its divestiture.

Royalties

The Conventional 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 crude oil and natural gas production. Natural gas wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital and direct operating costs incurred to process and transport the Crown’s share of raw gas at producer- owned gas plants as well as transport the Crown’s share of residue gas, NGLs or oil through producer-owned sales pipelines.

In 2020, our effective royalty rate was 7.9 percent (2019 – 5.1 percent). The higher royalty rate is due to a reduction in capital and operating expenses in 2019 resulting in a reduced GCA recovery.

Expenses

Transportation

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 our Conventional production is sold into the Alberta market. Per-unit transportation costs averaged $2.46 per BOE (2019 – $2.31 per BOE), due to lower sales volumes and increased pipeline costs.

 

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Operating

Total operating costs decreased to $318 million (2019 – $337 million) through continuing efforts to optimize our operations and workforce, focusing on critical repair and maintenance activities and leveraging our infrastructure to lower the cost structure.

Per-unit operating costs increased to an average of $8.99 per BOE (2019 – $8.79 per BOE) primarily due to lower sales volumes partially offset by lower workforce costs, decreased property tax and lease costs primarily for lower lease rentals and from regulatory cost relief, and lower repairs and maintenance as a result of lower activity and deferrals.

Netbacks

 

($/BOE)    2020             2019             2018 (1)  

Sales Price

                  17.84                      17.95                          19.31  

Royalties

      1.23          0.83          1.67  

Transportation and Blending

      2.46          2.31          1.97  

Operating Expenses

      8.99          8.79          8.58  

Netback Excluding Realized Risk Management

      5.16          6.02          7.09  

Realized Risk Management Gain (Loss)

      (0.01 )         (0.01 )         (0.59 ) 

Netback Including Realized Risk Management

      5.15          6.01          6.50  
                              

 

(1) 

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

DD&A and Exploration Expense

We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate accounts for expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. The average depletion rate was approximately $9.85 per BOE for the year ended December 31, 2020 (2019 – $9.15 per BOE).

For the year ended December 31, 2020, total Conventional DD&A was $880 million (2019 – $319 million). The increase was due to impairment charges of $555 million, as a result of the decline in forward crude oil and natural gas prices and a change in our future development plans, and higher DD&A rates.

Exploration expense of $82 million was recorded for the year ended December 31, 2020 (2019 – $64 million) as the carrying value of certain E&E assets were not considered to be recoverable.

Divestiture

On December 2, 2020, we sold our Marten Hills assets in northern Alberta to Headwater Exploration Inc. (“Headwater”) for total consideration of $138 million, excluding the retained gross overriding royalty interest (“GORR”). A before-tax gain of $79 million was recorded on the sale (after-tax – $65 million). Total consideration received consists of $33 million cash, 50 million common shares valued at $97 million and 15 million share purchase warrants valued at $8 million at the date of close. The share purchase warrants have a three-year term and an exercise price of $2.00 per share. We retained a GORR in the Marten Hills assets which was reclassified from E&E to PP&E for $41 million at the date of close. The investment in Headwater is held in other assets.

Capital Investment

In 2020, we invested $78 million compared with $103 million in 2019. Capital investment focused on the disciplined development of our Conventional assets, which encompassed maintaining safe and reliable operations, acquiring seismic data, start-up of a recompletion program to optimize existing production and commencement of a drilling program targeting low-risk, high-return development.

 

($millions)    2020             2019 (1)             2018 (1)  

Seismic

      5          -          -  

Drilling and Completions

      27          32          123  

Facilities

      20          34          58  

Other

      26          37          47  

Capital Investment (2)

                          78                              103                          228  
                              

 

(1) 

In Q1 2020, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified.

(2) 

Includes expenditures on PP&E and E&E assets.

Drilling Activity

In 2020 there were six net wells drilled, one net well completed and three net wells were tied-in and brought on production. In 2019, there were 11 net wells drilled, two net wells completed and three net wells tied-in.

 

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REFINING AND MARKETING

In 2020, we:

 

·  

Managed to economic crude oil runs of 372,000 barrels per day, lower than 2019 in response to the economic slowdown due to COVID-19;

·  

Reported Operating Margin of negative $388 million, a decrease of $1,125 million compared with 2019, due to lower global crude oil and refined product pricing, which led to decreased market crack spreads and lower crude advantage, and decreased crude oil runs, partially offset by lower operating costs;

·  

Recorded an impairment charge of $450 million, as additional DD&A expense, associated with the Borger cash-generating unit (“CGU”); and

·  

Completed the temporary ramp down of our crude-by-rail program in the second quarter until pricing fundamentals supported its continuation in the fourth quarter.

Financial Results

 

($ millions)    2020             2019 (1)             2018 (1) (2)  

Revenues

      6,051          10,513          11,183  

Purchased Product

      5,397          8,795          9,201  

Inventory Write-Down (Reversal)

      239          49          60  

Gross Margin

      415          1,669          1,922  

Expenses

                                                                                            

Operating

      824          948          927  

(Gain) Loss on Risk Management

      (21 )         (16 )         (1 ) 

Operating Margin

      (388 )         737          996  

Depreciation, Depletion and Amortization

      739          280          222  

Segment Income (Loss)

      (1,127 )         457          774  
                              
(1) 

The comparative period has been reclassified to conform with current period treatment of non-cash inventory write-downs and reversals.

(2) 

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

Refinery Operations (1)

 

      2020      2019      2018  

Crude Oil Capacity (Mbbls/d)

      495        482        460  

Crude Oil Runs (Mbbls/d)

                          372                            443                            446  

Heavy Crude Oil

      149        177        191  

Light/Medium

      223        266        255  

Refined Products (Mbbls/d)

      385        466        470  

Gasoline

      195        223        233  

Distillate

      127        167        156  

Other

      63        76        81  

Crude Utilization (percent)

      75        92        97  

 

(1) 

Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.

On a 100 percent basis, the Refineries had total processing capacity re-rated on January 1, 2020 to 495,000 gross barrels per day of crude oil. The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil processed, such as WCS and Christina Dilbit Blend, is dependent on the quality and quantity of available crude oil with the total input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in the Refineries relative to the total capacity.

Crude oil runs and refined product output decreased in 2020 compared with 2019 as both Refineries implemented crude rate reductions in response to the reduced demand due to COVID-19. In 2019, operational performance was impacted by unplanned outages, planned maintenance and turnaround activities at both Refineries.

Crude-By-Rail Terminal

Our crude-by-rail program was suspended in the first quarter in response to the low price market environment. The suspension was completed during the second quarter and lifted in the fourth quarter as market conditions improved. In 2020, we loaded an average of 32,213 barrels per day (22,891 barrels per day of our volumes) from our Bruderheim crude-by-rail terminal compared with an average of 65,293 barrels per day (45,324 barrels per day of our volumes) in 2019.

Gross Margin

While market crack spreads are an indicator of margin from processing crude oil into refined products, 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

 

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secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the Refineries; and the cost of feedstock. Our feedstock costs are valued on a FIFO accounting basis.

In 2020, Refining and Marketing gross margin decreased $1,254 million resulting from decreased market crack spreads and crude advantage due to lower global crude oil and refined product pricing, and reduced crude oil runs.

In the year ended December 31, 2020, the cost of Renewable Identification Numbers (“RINs”) was $177 million (2019 – $99 million). RIN costs increased, primarily due to higher pricing, partially offset by lower volume obligations. In 2020, RINs prices have been volatile and have steadily increased as RIN generation declined year over year, and at the same time RIN demand increased following a federal court decision to reduce the number of small refiners eligible for hardship exemptions.

Operating Expense

Primary drivers of operating expenses in 2020 were labour, maintenance, and utilities. Operating expenses decreased primarily due to lower maintenance activity compared with 2019 and lower utility 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 to 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 $739 million compared with $280 million in 2019. The increase in DD&A is primarily due to an impairment charge of $450 million related to the Borger CGU.

Capital Investment

 

($ millions)                        2020                                   2019                                   2018 (1)  

Wood River Refinery

      158          128          119  

Borger Refinery

      85          100          85  

Marketing

      33          52          4  

Capital Investment

          276          280          208  
                              
(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

Capital expenditures in 2020 focused primarily on yield enhancement, reliability and maintenance projects, as well as storage infrastructure projects.

CORPORATE AND ELIMINATIONS

In 2020, our risk management activities resulted in:

·  

Unrealized risk management losses of $56 million (2019 – $149 million) due to the realization of settled positions and changes in commodity prices compared with the prices at the end of the prior year; and

·  

Realized foreign exchange risk management losses of $5 million (2019 – gain of $1 million and loss of $1 million on interest rate swap contracts).

Transactions typically span across periods in order to execute the optimization strategy and these transactions reside across both realized and unrealized risk management.

Expenses

 

($ millions)                        2020                                 2019                                 2018 (1)  

General and Administrative (2)

     292          331          1,020  

Finance Costs

      536          511          627  

Interest Income

      (9 )         (12 )         (19 ) 

Foreign Exchange (Gain) Loss, Net

      (181 )         (404 )         854  

Transaction Costs

      29          -          -  

Re-measurement of Contingent Payment

      (80 )         164          50  

(Gain) Loss on Divestiture of Assets

      (81 )         (2 )         795  

Other (Income) Loss, Net

      40          9          13  
     546          597          3,340  
                              
(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

(2)

Onerous contract provisions of $629 million in 2018 have been reclassified to G&A.

General and Administrative

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 2020, G&A expenses were $39 million lower

 

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primarily due to lower employee long-term incentive costs and operating costs associated with our real estate portfolio, partially offset by an onerous contract provision of $18 million.

Finance Costs

Finance costs increased by $25 million primarily due to a discount of $25 million on the repurchase of unsecured notes compared with $63 million in 2019.

The weighted average interest rate on outstanding debt for the year ended December 31, 2020 was 4.9 percent (2019 – 5.1 percent).

Foreign Exchange

 

($ millions)                       2020                                2019                                2018  

Unrealized Foreign Exchange (Gain) Loss

     (131 )        (827 )        649  

Realized Foreign Exchange (Gain) Loss

     (50 )        423         205  
                           
    (181 )        (404 )        854  
                           

In 2020, unrealized foreign exchange gains of $131 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, 2020 was two percent stronger compared with December 31, 2019, resulting in unrealized gains.

Transaction Costs

Prior to December 31, 2020, we incurred transaction costs of $29 million for costs related to the Arrangement, excluding common share, preferred share and warrant issuance costs.

Re-measurement of Contingent Payment

Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips Company and certain of its subsidiaries (“ConocoPhillips”) during the five years subsequent to the closing date of the acquisition from ConocoPhillips of their 50 percent interest in the FCCL Partnership on May 17, 2017 (“the Conoco 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 payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment.

The contingent payment is accounted for as a financial option. The fair value of $63 million as at December 31, 2020 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. For the year ended December 31, 2020, a non-cash re-measurement gain of $80 million was recorded.

Average WCS forward pricing for the remaining term of the contingent payment is $42.93 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately $42.40 per barrel and $43.80 per barrel.

Other (Income) Loss, Net

For the year ended December 31, 2020, recorded a $100 million loss related to the Keystone XL pipeline project.

The Government of Canada passed the CEWS as part of its COVID-19 Economic Response Plan. The program is effective from March 15, 2020 to June 2021. For the year ended December 31, 2020, we recorded $40 million in other income from the CEWS program.

In 2020, we recognized $24 million of lease income (2019 - $17 million). Lease income is earned on tank subleases, operating leases related to our real estate ROU assets in which we are the lessor, and from the recovery of non-lease components for operating costs and unreserved parking related to our net investment in finance leases. Finance leases are included in other assets as net investment in finance leases.

DD&A

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements, office furniture, and certain ROU assets. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. ROU 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 2020 was $161 million (2019 – $107 million), of which $52 million of previously capitalized PP&E costs relating to information technology assets were written off due to synergies identified as a result of the Arrangement.

 

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Income Tax

 

($ millions)                       2020                                2019                                2018  

Current Tax

          

Canada

     (14 )        14         (128 ) 

United States

     1         3         2  
                           

Current Tax Expense (Recovery)

     (13 )        17         (126 ) 

Deferred Tax Expense (Recovery)

     (838 )        (814 )        (884 ) 
                           

Total Tax Expense (Recovery)

     (851 )        (797 )        (1,010 ) 
                           

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

 

($ millions)                       2020                                2019                                2018  

Earnings (Loss) From Continuing Operations Before Income Tax

     (3,230 )        1,397         (3,926 ) 

Canadian Statutory Rate (percent)

     24.0         26.5         27.0  
                           

Expected Income Tax Expense (Recovery) From Continuing Operations

     (775 )        370         (1,060 ) 

Effect of Taxes Resulting From:

          

Statutory and Other Rate Differences

     19         (52 )        (57 ) 

Non-Taxable Capital (Gains) Losses

     (42 )        (38 )        89  

Non-Recognition of Capital (Gains) Losses

     (42 )        (39 )        87  

Adjustments Arising from Prior Year Tax Filings

     (8 )        4         3  

Alberta corporate rate reduction

     (7 )        (671 )        -  

Recognition of U.S. Tax Basis

     -         (387 )        (78 ) 

Other

     4         16         6  
                           

Total Tax Expense (Recovery) From Continuing Operations

     (851 )        (797 )        (1,010 ) 
                           
Effective Tax Rate (percent)     26.3         (57.1 )        25.7  
                           

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and with consideration of the current economic environment, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.

For the year ended December 31, 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU, Conventional CGUs and current period operating losses that will be carried forward, excluding unrealized foreign exchange gains and losses on long-term debt. In 2020, the Government of Alberta accelerated the reduction in the provincial corporate tax rate from 12 percent to eight percent.

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, the Company recorded a deferred income tax recovery of $671 million for the year ended December 31, 2019. In addition, the Company recorded a deferred income tax recovery of $387 million due to an internal restructuring of the Company’s U.S. operations resulting in a step-up in the tax basis of the Company’s refining assets.

In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down of the Conventional E&E assets and a $78 million recovery arising from an adjustment to the tax basis of the Company’s refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its interest in WRB Refining LP (“WRB”), which due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. The maximum recovery related to the carry back of losses to recover tax paid was reached in 2018.

Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and the actual amounts subsequently reported on the tax returns, and other permanent differences.

Capital Investment

Capital expenditures of $60 million for 2020 focused primarily on supporting investments in technology and infrastructure to modernize our workplace, improve our cost structure and reduce costs and risk.

 

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DISCONTINUED 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 gain on discontinuance of $220 million was recorded on the sale.

QUARTERLY RESULTS

 

Our results over the last four quarters were impacted by the volatility in commodity prices primarily due to the impacts of COVID-19 and OPEC and non-OPEC production output decisions. Light oil benchmark prices were low and volatile throughout the majority of 2020, compared with the price of WTI in 2019. WTI fell 19 percent to average US$46.17 per barrel in the first quarter compared with US$56.96 per barrel in the fourth quarter of 2019 and dropped further to average US$27.85 per barrel in the second quarter with a recovery to average US$42.66 per barrel in the fourth quarter. Average WTI and WCS benchmark prices decreased 25 percent and 19 percent, respectively in the fourth quarter of 2020 compared with 2019. As a result, our Operating Margin from continuing operations was $625 million in the fourth quarter of 2020, a decrease from $864 million in the fourth quarter of 2019. Net Loss was $153 million compared with Net Earnings of $113 million in 2019.

Selected Operating and Consolidated Financial Results

 

($ millions, except per share   

 

2020

     2019  
amounts)    Q4     Q3     Q2     Q1     Q4     Q3      Q2      Q1  

Average Commodity Prices

                     

Brent

      45.24       43.37       33.27       50.96       62.50       62.00        68.34        63.88  

WTI

      42.66       40.93       27.85       46.17       56.96       56.45        59.83        54.90  

WCS

      33.36       31.84       16.38       25.64       41.13       44.21        49.18        42.53  

Chicago Market Crack Spread

      7.05       7.89       6.44       8.79       12.27       16.72        21.44        13.57  
     

Production Volumes

                     

Liquids (barrels per day)

      405,280       411,788       400,050       416,802       400,329       380,699        371,390        370,983  

Natural Gas (MMcf per day)

      371       360       392       395       403       407        432        458  

Total Production (BOE per day)

      467,202       471,799       465,415       482,594       467,448       448,496        443,318        447,270  
     

Refinery Operations

                     

Crude Oil Runs (Mbbls/d)

      338       382       325       442       456       465        474        375  

Refined Products (Mbbls/d)

      350       397       332       460       477       485        501        402  

Revenues

      3,426       3,659       2,174       3,968       4,838       4,736        5,603        5,004  
     

Operating Margin (1)

      625       594       291       (589 )      864       1,080        1,277        1,239  
     

Cash From (Used in) Operating Activities

      250       732       (834 )      125       740       834        1,275        436  
     

Adjusted Funds Flow (2)

      341       414       (462 )      (146 )      687       928        1,082        1,005  
     

Operating Earnings (Loss)

      (551 )      (452 )      (414 )      (1,187 )      ( 164 )      284        267        69  

Per Share (3) ($)

      (0.45 )      (0.37 )      (0.34 )      (0.97 )      (0.13 )      0.23        0.22        0.06  

Net Earnings (Loss)

      (153 )      (194 )      (235 )      (1,797 )      113       187        1,784        110  

Per Share (3) ($)

      (0.12 )      (0.16 )      (0.19 )      (1.46 )      0.09       0.15        1.45        0.09  

Capital Investment (4)

      242       148       147       304       317       294        248        317  

Dividends

                     

Cash Dividends

      -       -       -       77       77       60        62        61  

Per Share ($)

      -       -       -       0.0625       0.0625       0.0500        0.0500        0.0500  

 

(1)

Additional subtotal found in Note 1 of the Consolidated Financial Statements and interim Consolidated Financial Statements, and defined in this MD&A.

(2)

Non-GAAP measure defined in this MD&A. The comparative periods have been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals.

(3)

Represented on a basic and diluted per share basis.

(4)

Includes expenditures on PP&E and E&E assets.

Fourth Quarter 2020 Results Compared With the Fourth Quarter 2019

Production Volumes

Total production in the fourth quarter of 2020 was in line with 2019. The fourth quarter reflects increased production levels in response to an improved pricing environment facilitated by the purchase of production curtailment credits and lifting of the mandatory curtailment level at the beginning of December 2020. This was partially offset by a planned turnaround and maintenance at Christina Lake and operational outages due to process

 

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treatment upsets at Foster Creek. In the fourth quarter of 2019, production was limited due to mandatory production curtailments set by the Government of Alberta, offset by curtailment relief equivalent to incremental increases in rail shipments from the Special Production Allowance (“SPA”).

In the fourth quarter of 2020, we sold 121,595 barrels per day, approximately 25 percent, of our Oil Sands production at sales locations outside of Alberta compared with 181,366 barrels per day, approximately 35 percent, in the fourth quarter of 2019.

Conventional production in the fourth quarter of 2020 decreased eight percent to 86,167 BOE per day mainly due to natural declines from lower sustaining capital investment. Production from the Marten Hills assets was approximately 2,000 barrels per day for the quarter.

Refining and Marketing Operations

Crude oil runs of 338,000 gross barrels per day and refined product output of 350,000 gross barrels per day were lower compared with the same period in 2019 due to economic crude rate reductions in response to reduced demand as a result of COVID-19. In the fourth quarter of 2019 operations were impacted by planned turnaround activities and a crude supply constraint at Wood River as a result of a Keystone pipeline leak, partially offset by optimization of the total crude input slate.

In the fourth quarter of 2020, our crude-by-rail program was reinstated from the temporary suspension announced earlier in the year. Total rail volumes loaded at our Bruderheim crude-by-rail terminal averaged 29,144 barrels per day (20,423 barrels per day of our volumes) in the fourth quarter of 2020 compared with 89,630 barrels per day (71,708 barrels per day of our volumes) in the same period of 2019.

Revenues

Total revenues decreased $1,412 million in the fourth quarter of 2020 compared with the same period of 2019. Refining and Marketing revenues decreased $1,210 million primarily due to lower refined product pricing consistent with the declines in the average refined product benchmark prices and lower refined product output due to the economic crude rate reductions, and decreased revenues from third-party crude oil and natural gas sales undertaken by the marketing group. Upstream revenues decreased by $256 million primarily due to lower realized liquids sales pricing of $38.57 per barrel compared with $47.12 per barrel in 2019, partially offset by lower royalties and decreased sales volumes.

Operating Margin From Continuing Operations Variance

 

LOGO

 

(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

Operating Margin decreased in the fourth quarter of 2020 due to:

·  

A lower average liquids sales price as a result of decreased crude oil benchmark prices;

·  

Lower Operating Margin from our Refining and Marketing segment due to lower market crack spreads, decreased crude oil runs, lower crude advantage; and

·  

Increased upstream operating expenses.

These decreases were partially offset by lower royalties primarily due to our lower realized crude oil sales price and a decrease in our transportation and blending costs due to a decrease in rail transportation costs.

Cash From Operating Activities and Adjusted Funds Flow

Total Cash From Operating Activities and Adjusted Funds Flow decreased in the fourth quarter of 2020 compared with the same period in 2019, primarily due to lower Operating Margin, as discussed above, transaction costs of $29 million and changes in non-cash working capital. Adjusted Funds Flow was further reduced by a $100 million loss related to the Keystone XL pipeline project.

 

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The change in non-cash working capital in the fourth quarter of 2020 was primarily due to an increase in accounts receivable and inventory, a decrease in income tax payable, and an increase in income tax receivable, partially offset by an increase in accounts payable. For 2019, the change in non-cash working capital was primarily due to an increase in accounts payable and a decrease in income tax receivable, partially offset by an increase in accounts receivable and inventory.

Operating Earnings (Loss)

Operating Loss increased in the three months ended December 31, 2020 compared with 2019 primarily due to higher DD&A due to $298 million in impairments and write-downs, lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above, and higher non-cash employee long-term incentive costs mainly as a result of the accelerated vesting of our Employee Stock Option Plan, performance share units (“PSUs”) and restricted share units (“RSUs”) held by non-executive employees due to the closing of the Arrangement, partially offset by non-operating realized foreign exchange losses of $nil compared with $122 million in 2019.

Net Earnings (Loss)

Net Loss of $153 million increased for the three months ended December 31, 2020 compared with Net Earnings of $113 million in 2019. The change was primarily due to higher Operating Loss, as discussed above, partially offset by non-operating unrealized foreign exchange gains of $358 million compared with $258 million in 2019 and a deferred income tax recovery of $182 million compared with $24 million in 2019.

Capital Investment

Capital investment from continuing operations in the fourth quarter of 2020 was $242 million, $75 million lower compared with the fourth quarter of 2019, primarily due to the reduction of our capital investment program in response to COVID-19.

OIL AND GAS RESERVES

 

We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy crude oil, light and medium oil, NGLs, conventional natural gas and shale gas proved and probable reserves.

Reserves

 

As at December 31, 2020   Bitumen          

Light and

Medium

Oil

           NGLs          

Conventional

Natural

Gas (1)

          Total  
(before royalties)   (MMbbls)            (MMbbls)            (MMbbls)            (Bcf)            (MMBOE)  

Proved

     4,812         7         50         965         5,030  

Probable

     1,520         6         31         601         1,656  
                                               

Proved plus Probable

     6,332         13         81         1,566         6,686  
                                               
As at December 31, 2019   Bitumen (2)          

Light and

Medium

Oil

           NGLs          

Conventional

Natural

Gas (1)

           Total  
(before royalties)   (MMbbls)            (MMbbls)            (MMbbls)            (Bcf)            (MMBOE)  

Proved

     4,826         9         60         1,242         5,103  

Probable

     1,594         8         37         783         1,768  
                                               

Proved plus Probable

     6,420         17         97         2,025         6,871  
                                               

 

(1)

Includes shale gas reserves that are not material.

(2)

Includes heavy crude oil reserves that are not material.

Developments in 2020 compared with 2019 include:

 

·  

Bitumen proved and proved plus probable reserves decreasing 14 million barrels and 88 million barrels, respectively, as additions from improved performance in Oil Sands were more than offset by the Marten Hills disposition and current year production;

·  

Light and medium oil proved and proved plus probable reserves decreasing two million barrels and four million barrels, respectively, as minor additions were more than offset by technical revisions attributed to updates to the Conventional development plan, reduced product pricing and current year production;

·  

NGLs proved and proved plus probable reserves decreasing 10 million barrels and 16 million barrels, respectively, as minor additions and a minor acquisition were more than offset by reductions due to technical revisions attributed to updates to the Conventional development plan, reduced product pricing and current year production; and

·  

Conventional natural gas proved and proved plus probable reserves decreasing 277 billion cubic feet and 459 billion cubic feet, respectively, as minor additions and a minor acquisition were more than offset by

 

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reductions due to technical revisions attributed to updates to the Conventional development plan, reduced product pricing and current year production.

The reserves data is presented as at December 31, 2020 using an average of forecasts (“IQRE Average Forecast”) by McDaniel & Associates Consultants Ltd. (“McDaniel”), GLJ Ltd. (“GLJ”) and Sproule Associates Limited (“Sproule”). The IQRE Average Forecast prices and costs are dated January 1, 2021. Comparative information as at December 31, 2019 uses the January 1, 2020 IQRE Average Forecast prices and costs.

As a result of the close of the Arrangement on January 1, 2021, including reported reserves from Husky, our total proved reserves and total proved plus probable reserves are anticipated to increase by approximately 1.2 billion BOE and 1.8 billion BOE, respectively.

Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) is contained in our AIF for the year ended December 31, 2020. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this MD&A in the Risk Management and Risk Factors section and the Advisory section in this MD&A.

Information concerning Husky and its reserves data and other oil and gas information as of December 31, 2020 may be found in the Husky AIF and the Husky MD&A, each of which is filed and available on SEDAR under Husky’s profile at sedar.com.

LIQUIDITY AND CAPITAL RESOURCES

 

 

($ millions)                        2020                                 2019                                 2018  

Cash From (Used in)

             

Operating Activities

      273          3,285          2,154  

Investing Activities

      (863 )         (1,432 )         (613 ) 

Net Cash Provided (Used) Before Financing Activities

      (590 )         1,853          1,541  

Financing Activities

      837          (2,413 )         (1,410 ) 

Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency

      (55 )         (35 )         40  
                              

Increase (Decrease) in Cash and Cash Equivalents

      192          (595 )         171  
                              
As at December 31,    2020             2019             2018  

Cash and Cash Equivalents

      378          186          781  

Debt

      7,562                6,699                9,164  

As at December 31, 2020, we were in compliance with all of the terms of our debt agreements.

Cash From (Used in) Operating Activities

For the year ended December 31, 2020, cash generated by operating activities decreased mainly due to lower Operating Margin, transaction costs of $29 million, partially offset by funding from the CEWS program and sublease income, and lower current taxes, as discussed in the Corporate and Eliminations section of this MD&A, and changes in non-cash working capital, as discussed in the Operating and Financial Results section of this MD&A.

Excluding the current portion of the contingent payment, our working capital was $653 million at December 31, 2020 compared with $842 million at December 31, 2019.

We anticipate that we will continue to meet our payment obligations as they come due.

Cash From (Used in) Investing Activities

Cash used in investing activities was lower in 2020 compared with 2019 primarily due to decreased capital investment in 2020.

Cash From (Used in) Financing Activities

In the first quarter of 2020, we repurchased US$100 million of unsecured notes for cash of US$81 million. In the third quarter of 2020 we issued US$1.0 billion in 5.375 percent senior unsecured notes due in 2025 and used the proceeds to repay $1.4 billion of borrowings on our committed credit facility.

In 2019, cash was used in financing activities primarily for the repayment of debt. We repaid US$1.8 billion of unsecured notes for cash consideration of US$1.7 billion ($2.3 billion).

Total debt, including short-term borrowings, as at December 31, 2020 was $7,562 million (December 31, 2019 – $6,699 million).

 

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Common Share Dividends

On April 2, 2020 we announced the temporary suspension of our common share dividend in response to the low global crude oil price environment. Prior to the suspension, we paid common share dividends of $77 million or 0.0625 per common share in the first quarter of 2020 (year ended December 31, 2019 – $260 million or $0.2125 per common share). The declaration of dividends is at the sole discretion of the Board and is considered quarterly. The Board declared a first quarter dividend of $0.0175 per common share, payable on March 31, 2021 to common shareholders of record as of March 15, 2021.

Cumulative Redeemable Preferred Share Dividend

The Board declared a first quarter dividend on the Series 1, 2, 3, 5, and 7 preferred shares, payable on March 31, 2021, in the amount of $8 million.

Available Sources of Liquidity

The following sources of liquidity are available at December 31, 2020:

 

($ millions)   Term           

Amount

    Available

  

Cash and Cash Equivalents

     Not applicable         378  

Committed Credit Facilities

      

Revolving Credit Facility – Tranche A

     November 2023         3,300  

Revolving Credit Facility – Tranche B

     November 2022         1,200  

Uncommitted Demand

      

Facilities Cenovus Energy Inc.

     Not applicable         600  

WRB Refining LP (Cenovus’s proportionate share)

     Not applicable         70  

In light of the current challenging economic conditions, we expect to fund our near-term cash requirements through cash from operating activities and prudent use of our balance sheet capacity including draws on our committed credit facilities and our uncommitted demand facilities and other corporate and financial opportunities that may be available to us.

Committed Credit Facilities

As at December 31, 2020, we had a total committed credit facility of $4.5 billion that consisted of a $1.2 billion tranche maturing on November 30, 2022 and a $3.3 billion tranche maturing November 30, 2023. During the second quarter, we added a committed credit facility with capacity of $1.1 billion, with a term of 364 days that was renewable for one year at our request and upon approval by the lenders, to further support our financial resilience. On December 31, 2020, we cancelled the $1.1 billion committed credit facility. As at December 31, 2020, no amount was drawn on the committed credit facility (December 31, 2019 - $265 million).

Uncommitted Demand Facilities

As at December 31, 2020, Cenovus had uncommitted demand facilities of $1.6 billion in place, of which $600 million may be drawn for general purposes or the full amount can be available to issue letters of credit. As at December 31, 2020, the Company had drawn no amounts (December 31, 2019 - $nil) on these facilities and there were outstanding letters of credit aggregating to $441 million (December 31, 2019 - $364 million).

WRB has uncommitted demand facilities of US$300 million (the Company’s proportionate share - US$150 million) available to cover short-term working capital requirements. As at December 31, 2020, US$190 million was drawn on these facilities, of which US$95 million ($121 million) was the Company’s proportionate share (December 31, 2019 – $nil).

Base Shelf Prospectus

Cenovus has in place a base shelf prospectus that allows us to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus will expire in October 2021. On July 30, 2020, we completed a public offering in the U.S., under the U.S. base shelf prospectus, of senior unsecured notes in the aggregate principal amount of US$1.0 billion due in 2025. As at December 31, 2020, US$3.7 billion remained available under the base shelf prospectus for permitted offerings.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. We define Capitalization as Net Debt plus Shareholders’ Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense (recovery), DD&A, E&E write-down, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent

 

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payment, gains (losses) on divestiture of assets, and other income (loss), net, calculated on a trailing twelve-month basis. These measures are used to steward our overall debt position and as measures of our overall financial strength.

 

As at December 31,               2020                 2019                 2018  

Net Debt to Capitalization (1) (percent)

     30       25       32  

Net Debt to Adjusted EBITDA (times)

     11.9x       1.6x       5.8x  
(1)

Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.

(2)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

A reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA can be found in Note 24 of the Consolidated Financial Statements.

Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may periodically be above the target due to factors such as persistently low commodity prices. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure the Company has sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, repurchase our common shares for cancellation, issue new debt, or issue new shares.

As at December 31, 2020, Cenovus’s Net Debt to Adjusted EBITDA was 11.9 times. Net Debt to Adjusted EBITDA increased compared with December 31, 2019 as a result of an increase in our borrowings, as mentioned in the Cash From (Used In) Financing Activities above, and a reduction in our trailing twelve-month adjusted EBITDA.

We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenants as defined in our committed credit facility agreements. Under the terms of Cenovus’s committed credit facility at the end of the year, we were required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. We were well below this limit at December 31, 2020.

Additional information regarding our financial measures and capital structure can be found in the notes to the Consolidated Financial Statements.

Share Capital and Stock-Based Compensation Plans

As at December 31, 2020, there were approximately 1,229 million common shares outstanding (2019 – 1,229 million common shares). Refer to Note 30 of the Consolidated Financial Statements for more details.

Refer to Note 32 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and deferred share unit (“DSU”) Plans.

Our outstanding share data is as follows:

 

As at January 31, 2021  

Units

Outstanding

(thousands)

           

Units

Exercisable

(thousands)

  

Common Shares (1) 

     2,017,404         N/A  

Common Share Warrants

     65,418         N/A  

Preferred Shares Series 1

     10,436         N/A  

Preferred Shares Series 2

     1,564         N/A  

Preferred Shares Series 3

     10,000         N/A  

Preferred Shares Series 5

     8,000         N/A  

Preferred Shares Series 7

     6,000         N/A  

Stock Options (2)

     30,499         23,305  

Other Stock-Based Compensation Plans

     3,715               1,293  
(1)

ConocoPhillips continued to hold 208 million common shares issued as partial consideration related to the Conoco Acquisition.

(2)

Includes Cenovus Replacement Options (defined below) issued pursuant to the Arrangement in replacement of all issued and outstanding Husky stock options.

Capital Investment Decisions

Our approach on the financial framework of the combined company will be consistent with the parameters we have set for Cenovus in prior years. We will continue to evaluate all opportunities based on a US$45.00 per barrel WTI price with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics. This approach positions us to be financially resilient in times of lower cash flows. Balance sheet strength continues to be a top priority and we plan to continue to direct our Free Funds Flow towards debt reduction. We continue to target a Net Debt to EBITDA ratio not to exceed two times.

Our 2021 capital program for the combined company is forecast to be between $2.3 billion and $2.7 billion. The budget is focused on maintaining safe and reliable operations while positioning the Company to drive enhanced shareholder value and includes sustaining capital of approximately $2.1 billion to deliver upstream production of approximately 755,000 BOE per day and downstream throughput of approximately 525,000 barrels per day.

 

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($ millions)                       2020                                2019                                2018  

Adjusted Funds Flow (1)

     147         3,702         1,721  

Total Capital Investment

     841         1,176         1,363  
                           

Free Funds Flow (1) (2)

     (694 )        2,526         358  

Cash Dividends

     77         260         245  
    (771 )        2,266         113  
                           

 

(1)

The comparative period has been reclassified to conform with current period treatment of non-cash inventory write-downs and reversals.

(2)

Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.

We remain committed to maintaining and improving our current investment-grade credit ratings. This includes our continued focus on allocating free funds flow to reduce Net Debt to less than $10 billion and targeting a longer-term Net Debt level at or below $8 billion.

The combined company’s adjusted funds flow is expected to fully fund sustaining capital and shareholder distributions. The Board declared a first quarter dividend of $0.0175 per common share, payable on March 31, 2021, to common shareholders of record as of March 15, 2021. The Board declared a first quarter dividend on the Series 1, 2, 3, 5, and 7 preferred shares, payable on March 31, 2021, in the amount of $8 million.

Contractual Obligations and Commitments

Cenovus has obligations for goods and services entered into in the normal course of business. Obligations are primarily related to transportation agreements, our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less than one year are excluded. For further information, see the notes to Consolidated Financial Statements.

As at December 31, 2020, total commitments were $23 billion, of which $21 billion are for various transportation and storage commitments. Terms are up to 20 years subsequent to the date of commencement and should help align with the Company’s future transportation requirements with anticipated production growth. Transportation and storage commitments include future commitments relating to storage tank leases of $31 million, that have not yet commenced.

 

    Expected Payment Date  
($ millions)               2021                        2022                        2023                        2024                        2025            Thereafter                      Total  

Commitments

                          

Transportation and Storage (1)

     1,014         954         1,341         1,444         1,107         15,537         21,397  

Real Estate (2)

     34         36         38         41         44         604         797  

Capital Commitments

     1         2         -         -         -         -         3  

Other Long-Term Commitments

     104         45         32         32         24         85         322  
                                                                   

Total Commitments (3)

     1,153         1,037         1,411         1,517         1,175         16,226         22,519  

Other Obligations

                          

Long-term Debt (Principal and Interest)

     385         1,024         941         346         1,620         8,627         12,943  

Decommissioning Liabilities

     41         45         41         42         41         2,429         2,639  

Contingent Payment

     36         28         -         -         -         -         64  

Lease Liabilities (Principal and Interest) (4)

     254         237         208         203         162         1,412         2,476  
                                                                   

Total Commitments and Obligations

     1,869         2,371         2,601         2,108         2,998         28,694         40,641  
                                                                   

 

(1)

Includes transportation commitments of $14 billion (December 31, 2019 – $13 billion) that are subject to regulatory approval or have been approved but are not yet in service.

(2)

Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(3)

Contracts undertaken on behalf of WRB are reflected at our 50 percent interest.

(4)

Lease contracts related to office space, railcars, storage assets, drilling rigs and other refining and field equipment.

We continue to focus on mid-term strategies to broaden market access for our crude oil production. We continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil.

As at December 31, 2020, there were outstanding letters of credit aggregating $441 million issued as security for performance under certain contracts (December 31, 2019 – $364 million).

Liquidity and Capital Resources Subsequent to the Arrangement

Share Capital and Stock-Based Compensation

At the closing of the Arrangement on January 1, 2021, we acquired all of the issued and outstanding Husky common shares in consideration for the issuance of 0.7845 Cenovus common shares and 0.0651 Cenovus warrants (“Cenovus Warrants”) for each Husky common share. All the issued and outstanding Husky preferred shares were exchanged for Cenovus preferred shares with substantially identical terms, and all issued and outstanding Husky stock options were exchanged for Cenovus replacement stock options (“Cenovus Replacement Options”). Each Cenovus Replacement Option entitles the holder to acquire 0.7845 of a Cenovus common share at an exercise price per share of a Husky stock option divided by 0.7845. Refer to Notes 30 and 39 of the Consolidated Financial Statements for more details.

 

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The Arrangement resulted in the accelerated vesting of certain stock-based compensation plans of the Company. Refer to Notes 32 and 39 of the Consolidated Financial Statements for more details. In accordance with their terms, the PSUs and RSUs may be settled, at the discretion of Cenovus, in Cenovus common shares, cash, or a combination of both based on the 30-day volume weighted average trading price prior to the date of closing. The obligations associated all PSUs and RSUs that were settled in connection with the completion of the Arrangement were paid in cash in January 2021.

In connection with the Arrangement, a DSU holder that ceased to be a Cenovus director or employee will be entitled to the settlement and redemption of their DSUs, in cash based on the five day volume weighted average trading prior to the date of redemption, in accordance with the terms of the related DSU Plan.

Liquidity and Commitments

At closing of the Arrangement on January 1, 2021, Cenovus obtained access to additional sources of capital including: $735 million in cash and cash equivalents, $3.7 billion available on Husky’s committed credit facilities and $508 million available on Husky’s uncommitted demand facilities. Husky’s committed credit facilities have a capacity of $4.0 billion and its uncommitted demand facilities have a capacity of $975 million, of which $850 million may be drawn for general purposes, or the full amount can be available to issue letters of credit.

We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service (“Moody’s”) and DBRS Limited and re-establishing investment grade ratings at Fitch Ratings (“Fitch”). The cost and availability of borrowing, and access to sources of liquidity and capital is dependent on current credit ratings as determined by independent rating agencies and market conditions.

The Arrangement resulted in the assumption of Husky’s known non-cancellable contracts and other commercial commitments. On January 1, 2021, total commitments assumed by Cenovus were $19 billion, of which $2 billion were for various transportation commitments that are subject to regulatory approval or have been approved, but are not yet in service.

Additional information concerning Husky’s liquidity and commitments as of December 31, 2020 may be found under the sections Sources of Liquidity and Contractual Obligations, Commitments and Off-Balance Sheet Arrangements in the Husky MD&A, which is filed and available on SEDAR under Husky’s profile at sedar.com.

Legal Proceedings

We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements.

Contingent Payment

In connection with the Conoco Acquisition and related to our Oil Sands production, we agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. As at December 31, 2020, the estimated fair value of the contingent payment was $63 million. As at December  31, 2020, no amount was payable under the agreement. See the Corporate and Eliminations section of this MD&A for more details.

RISK MANAGEMENT AND RISK FACTORS

 

We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the energy industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition, results of operations and cash flows, which may reduce or restrict our ability to pursue our strategic priorities, respond to changes in our operating environment, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and may materially affect the market price of our securities.

Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of Cenovus’s risk and is integrated with our Operations Management Systems. In addition, we continuously monitor our risk profile as well as industry best practices.

Risk Governance

The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Building on the ERM Policy, we have established risk management standards, a risk management framework and risk assessment tools, including risk matrices. Our risk management framework contains the key attributes recommended by the International Organization for Standardization (“ISO”) in its ISO 31000 – Risk Management Guidelines. The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as through regular updates.

 

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Risk Factors

The following discussion describes the financial, operational, regulatory, environmental, reputational and other risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks, have a material impact on our business, financial condition, results of operations, cash flows, or reputation and should be considered when purchasing securities of Cenovus.

Pandemic Risk

The COVID-19 pandemic and measures taken in response by governments and health authorities around the world have resulted in a significant slow-down in global economic activity that has reduced the demand for, and adversely affected the prices of, commodities that are closely linked to Cenovus’s financial performance, including crude oil, refined products (such as jet fuel, diesel and gasoline), natural gas and electricity, and also increases the risk that storage for crude oil and refined products could reach capacity in certain geographic locations in which Cenovus operates variant strains of COVID-19 have been identified. While some economies have started to re-open and vaccines have been developed, resurgences in cases of COVID-19 have occurred in certain locations and the risk of additional resurgences in other locations remains high. This creates ongoing uncertainty that has resulted in and could result in further restrictions on movement and businesses being re-imposed or imposed on a stricter basis, which could negatively impact demand for commodities and commodity prices and negatively impact our business, results of operations and financial condition. It is impossible at this point to predict precisely the duration or extent of the impacts of the COVID-19 pandemic on Cenovus’s employees, customers, partners and business or when economic activity will normalize.

The COVID-19 pandemic may increase our exposure to, and magnitude of, each of the risks identified in the Risk Management and Risk Factors section of this MD&A. Our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund dividend payments and/or business plans may, in particular, without limitation, be adversely impacted as a result of the pandemic and/or decline in commodity prices as a result of:

 

·  

The shut-down of facilities or the delay or suspension of work on major capital projects due to workforce disruptions or labour shortages caused by workers becoming infected with COVID-19, or government or health authority mandated restrictions on travel by workers or closure of facilities, workforce camps or worksites;

·  

Disruptions to global supply chains, such as suppliers and third-party vendors experiencing similar workforce disruptions or being ordered to cease operations;

·  

Reduced cash flows resulting in less funds from operations being available to fund our capital expenditure budget;

·  

Reduced commodity prices resulting in a reduction in the volumes and value of our reserves. See “Commodity Prices” below;

·  

Commodity storage constraints resulting in the curtailment or shutting in of production;

·  

A decrease in refined product volumes, the demand for refined products, or refinery utilization rates;

·  

Counterparties being unable to fulfill their contractual obligations to us on a timely basis or at all;

·  

The inability to deliver products to customers or otherwise get products to market caused by border restrictions, road or port closures or pipeline shut-ins, including as a result of pipeline companies suffering workforce disruptions or otherwise being unable to continue to operate;

·  

The capabilities of our information technology systems and the potential heightened threat of a cyber-security breach arising from the number of employees, customers, and partners working remotely; and

·  

Our ability to obtain additional capital including, but not limited to, debt and equity financing being adversely impacted as a result of unpredictable financial markets, commodity prices and/or a change in market fundamentals.

The extent to which COVID-19 impacts our business, results of operations and financial condition will depend on future developments, which are highly uncertain and are difficult to predict, including, but not limited to, the severity, duration, spread or resurgence of COVID-19 or any variants thereof; the timing, extent and effectiveness of actions taken to contain or treat COVID-19 or its variants, including the availability, distribution rate and effectiveness of any vaccines; and the speed and extent to which normal economic and operating conditions resume. The potential impacts of COVID-19 to our business, results of operations and financial condition could be more significant in the current year as compared with 2020. Even after the COVID-19 pandemic has subsided, we may continue to experience materially adverse impacts to our business as a result of the pandemic’s global economic impact.

There are no comparable recent events that provide guidance as to the effect the spread of COVID-19 as a global pandemic may have, and, as a result, the ultimate impact of the outbreak is highly uncertain and subject to change. Management does not yet know the full extent of the impacts on our business and operations or the global economy as a whole.

We have taken proactive steps to protect the health and safety of our staff and the continuity of our business in response to the COVID-19 pandemic. We continue to follow guidance received from the Federal, Provincial and state governments and public health officials. We also have a comprehensive Business Continuity Plan to ensure continued safe and reliable operations in the event of a COVID-19 outbreak at any of our workplaces. Despite our best efforts, the COVID-19 pandemic may result in new legal disputes, including class action claims.

 

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Financial Risk

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions. Financial risks include, but are not limited to: fluctuations in commodity prices, development or operating costs; risks related to Cenovus’s hedging activities; exposure to counterparties; availability of capital and access to sufficient liquidity; risks related to Cenovus’s credit ratings; and fluctuations in foreign exchange and interest rates. In addition, we identify risks related to our ability to pay a dividend to shareholders; and risks related to internal control over financial reporting (“ICFR”). Changes in financial management and/or market conditions could impact a number of factors including, but not limited to, Cenovus’s cash flows, Cenovus’s ability to maintain desirable ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization, Cenovus’s financial condition, results of operations and growth, the maintenance of our existing operations and business plans, financial strength of our counterparties, access to capital and cost of borrowing.

Excess Crude Oil Supply Risk

It is not known how long low commodity price conditions will continue, however if the situation continues, worsens or is exacerbated further by the impact of COVID-19, and global crude oil prices remain low for a prolonged period, our production, project development, profitability, cash flows, ability to access additional capital, and securities trading price, among other things, could be adversely impacted. While OPEC members agreed to certain production cuts through April 2022 and have reconfirmed their commitment to a stable oil market amid the global demand reduction caused by the pandemic, the stated reductions have since been varied and there can be no assurances that OPEC members and other oil exporting nations will abide by the agreed reductions or continue to agree to actions to stabilize oil prices. Uncertainty regarding the future actions of such nations may lead to increased commodity price volatility. See “Commodity Prices” below.

Commodity Prices

Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural gas and NGLs. Crude oil prices are impacted by a number of factors including, but not limited to: global and regional supply of and demand for crude oil; global economic conditions including factors impacting global trade; the actions of OPEC and other oil exporting nations including, without limitation, compliance or non-compliance with quotas agreed upon by OPEC members and decisions by OPEC not to impose production quotas on its members; actions by the Government of Alberta including, without limitation, imposing, amending, or lifting crude oil production curtailments or SPA for crude-by-rail, and compliance or non-compliance with imposed crude oil production curtailments or SPA for crude-by-rail; enforcement of government or environmental regulations; public sentiment towards the use of non-renewable resources, including crude oil; political stability and social conditions in oil producing countries, market access constraints and transportation interruptions (pipeline, marine or rail); prices and availability of alternate fuel sources; outbreak of war; outbreak or continuation of a pandemic; terrorist threats; technological developments; the occurrence of natural disasters; and weather conditions.

Cenovus’s natural gas and NGL production is currently located in Western Canada and Asia Pacific. Western Canadian natural gas prices are impacted by a number of factors including, but not limited to: North American supply and demand; developments related to the market for liquefied natural gas; prices and availability of alternate sources of energy; government or environmental regulations; public sentiment towards the use of non-renewable resources, including natural gas and NGLs; market access constraints and transportation interruptions; economic conditions; technological developments; the occurrence of natural disasters; and weather conditions.

Refined product prices are impacted by a number of factors including, but not limited to: global and regional supply and demand for refined products; market competitiveness; levels of refined product inventories; refinery availability; planned and unplanned refinery maintenance; current and potential future environmental regulations pertaining to the production and use of refined products; prices and availability of alternate sources of energy; public sentiment towards the use of refined products; prices and the availability of alternate fuel sources; technological developments; the occurrence of natural disasters; and weather conditions. In addition, and relating to the level of future demand (and corresponding price levels) for each of crude oil, refined products and natural gas, there has been a significant increase in focus recently on the timing for and pace of the transition to a lower-carbon economy. See “Climate Change Transition – Demand and Commodity Prices” below. All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.

Our financial performance is also impacted by discounted or reduced commodity prices for our oil sands production relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell products to domestic or international markets and the quality of oil produced. Of particular importance to us are diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy crude oil. Bitumen is more expensive for refineries to process and therefore generally trades at a discount to the market price for light and medium crude oil and heavy crude oil.

The financial performance of our refining operations is impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production changes to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate

 

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accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact on our business.

Fluctuations in the price of commodities, associated price differentials and refining margins may impact our ability to meet guidance targets, the value of our assets, our cash flows and our ability to maintain our business and fund projects. A substantial decline in these commodity prices or extended period of low commodity prices may result in an inability to meet all of our financial obligations as they come due, a delay or cancellation of existing or future drilling, development or construction programs, curtailment in production (independent of any crude oil production curtailment mandated by the Government of Alberta then in effect), unutilized long-term transportation commitments and/or low utilization levels at Cenovus’s refineries. Fluctuations in commodity prices, associated price differentials and refining margins impact our financial condition, results of operations, cash flows, growth, access to capital and cost of borrowing.

The commodity price risks noted above, as well as other risks such as market access constraints and transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully described herein, and may have a material impact on our business, financial condition, results of operations, cash flows or reputation, may be considered to be indicators of impairment. Another indication of impairment is the comparison of the carrying value of our assets to our market capitalization.

As discussed in this MD&A, we conduct an assessment, at each reporting date, of the carrying value of our assets in accordance with IFRS. If crude oil, refined product and natural gas prices decline significantly and remain at low levels for an extended period of time, or if the costs of our development of such resources significantly increases, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.

We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts, market access commitments and generally through our access to committed credit facilities. In certain instances, Cenovus will use derivative instruments to manage exposure to price volatility on a portion of its refined product, oil and gas production, inventory or volumes in long-distance transit. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 35 and 36 of the Consolidated Financial Statements and “Hedging Activities” below.

Additionally, the factors discussed under the headings “Pandemic Risk” and “Excess Crude Oil Supply Risk” could continue to negatively impact commodity prices. If crude oil, refined product and natural gas prices remain at low levels for an extended period, or if the costs of development of our resources significantly increases, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.

Development and Operating Costs

Our financial outlook and performance is significantly affected by the cost of developing, sustaining and operating our assets. Development and operating costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies; inflationary price pressure; changes in regulatory compliance costs; scheduling delays; failure to maintain quality construction and manufacturing standards; and supply chain disruptions, including access to skilled labour. Electricity, water, diluent, chemicals, supplies, reclamation, abandonment and labour costs are examples of operating costs that are susceptible to significant fluctuation.

Hedging Activities

Cenovus’s Market Risk Management Policy, which has been approved by the Board, allows Management to use derivative instruments including exchange-traded future contracts, commodity put and call options and other approved instruments as needed to help mitigate the impact of changes in crude oil and natural gas prices, crude oil differentials, diluent or condensate supply prices and differentials, refined product and crack spread margins, as well as fluctuations in foreign exchange rates and interest rates. Cenovus may also use firm commitments for the purchase or sale of crude oil, natural gas and refined products. Cenovus also uses derivative instruments in various operational markets to help optimize our supply costs or sales of our production.

The use of such hedging activities exposes us to risks which may cause significant loss. These risks include, but are not limited to: changes in the valuation of the hedge instrument being not well correlated to the change in the valuation of the underlying exposures being hedged; change in price of the underlying commodity; lack of market liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; and the unenforceability of contracts.

There is risk that the consequences of hedging to protect against unfavourable market conditions may limit the benefit to us of commodity price increases or changes in interest rates and foreign exchange rates. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil, natural gas or refined products to fulfill our delivery obligations related to the underlying physical transaction.

We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts and market access commitments. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3, 35 and 36 of the Consolidated Financial Statements.

 

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Impact of Financial Risk Management Activities

In 2020, for Cash Flow derivatives, we incurred a realized loss due to the settlement of benchmark prices relative to our risk management contract prices. For Optimization derivatives, the realized loss was from our decisions to store rather than sell our physical crude oil and condensate volumes as well as hedging activity related to the transportation of crude and condensate. Cenovus uses its marketing and transportation initiatives, including storage and pipeline assets to optimize product mix, delivery points, transportation commitments and customer diversification, to inventory physical positions. At the time we make the decision to store crude oil and condensate volumes, the prices available for future periods we plan to sell in can be locked in and the improved margin realized in the future periods, which are superior to short-term prices. The risk management gains and losses offset corresponding fluctuations in revenues generated from the underlying physical sales.

Unrealized losses were recorded on our crude oil financial instruments in the twelve months ended December 31, 2020 primarily due to changes in commodity prices compared with prices at the end of the year and the realization of settled positions.

Transactions typically span across periods in order to execute the optimization strategy, and these transactions reside across both realized and unrealized risk management.

Sensitivities – Risk Management Positions

The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices on our open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

 

      Sensitivity Range    Increase     Decrease    

Crude Oil Commodity Price

    ± US$5.00 per bbl Applied to WTI and Condensate Hedges      (44 )      44    

Crude Oil Differential Price

    ± US$2.50 per bbl Applied to Differential Hedges Tied to Production      (2 )      2    

For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements.

Risks Associated with Derivative Financial Instruments

Financial instruments expose us to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Board-approved Credit Policy.

Financial instruments also expose us to the risk of a loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical transaction. Financial instruments may limit the benefit to us if commodity prices, interest or foreign exchange rates change. These risks are managed through hedging limits authorized according to our Market Risk Management Policy.

Exposure to Counterparties

In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders and other counterparties for the provision and sale of goods and services. If such counterparties do not fulfill their contractual obligations on a timely basis or at all, we may suffer financial losses, delays of our development plans or we may have to forego other opportunities which could materially impact our financial condition or operational results.

Credit, Liquidity and Availability of Future Financing

The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn, a change in market fundamentals, business operations, investor or lender sentiment towards our business and/or the industry in which we operate or credit rating, or significant unanticipated expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital, on terms acceptable to Cenovus or at all, could affect our ability to make future capital expenditures, to maintain desirable ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization and to meet all of our financial obligations as they come due, potentially creating a material adverse effect on our financial condition, results of operations, ability to comply with various financial and operating covenants, credit ratings and reputation.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, Cenovus may take actions such as reducing or suspending dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional capital that could have less favourable terms.

Our liquidity risk is mitigated through actively managing cash and cash equivalents, cash flow provided by operating activities, available credit facilities, and accessing the capital markets.

 

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We are required to comply with various financial and operating covenants under our credit facilities and the indentures governing our debt securities. We routinely review our covenants to ensure compliance. In the event that we do not comply with such covenants, our access to capital could be restricted or repayment could be accelerated.

Credit Ratings

Our company and our capital structure are regularly evaluated by credit rating agencies. Credit ratings are based on our financial and operational strength and a number of factors not entirely within our control, including conditions affecting the oil and gas industry generally, industry risks associated with climate change and an energy transition and the state of the economy. There can be no assurance that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency.

A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. A failure by Cenovus to maintain current credit ratings could affect our business relationships with counterparties, operating partners and suppliers.

If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post collateral in the form of cash, letters of credit or other financial instruments in order to establish or maintain business arrangements. Additional collateral may be required due to further downgrades below certain ratings thresholds. Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated.

Foreign Exchange Rates

Fluctuations in foreign exchange rates between various currencies may affect our results. Global prices for crude oil, refined products, and natural gas are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A change in the value of the Canadian dollar relative to the U.S. dollar will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas sales. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. We may periodically enter into transactions to manage our exposure to exchange rate fluctuations. However, the fluctuations in exchange rates are beyond our control and could have a material adverse effect on our cash flows, results of operations and financial condition.

Interest Rates

We may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings. An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded, both of which could negatively impact financial results. Additionally, we are exposed to interest rate fluctuations upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates.

We may periodically enter into transactions to manage our exposure to interest rate fluctuations.

Dividend Payment and Repurchase of Securities

The payment of dividends, continuation of Cenovus’s dividend reinvestment plan and any potential repurchase by Cenovus of its securities is at the discretion of the Board, and is dependent upon, among other things, financial performance, debt covenants, satisfying solvency testing, our ability to meet financial obligations as they come due, working capital requirements, future tax obligations, future capital requirements, commodity prices and other business and risk factors set forth in this MD&A.

Disclosure Controls and Procedures and ICFR

Based on their inherent limitations, disclosure controls and procedures and ICFR may not prevent or detect misstatements, and even those controls determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation.

Operational Risk

Operational risks are those risks that affect our ability to continue operations in the ordinary course of business. Our operations are subject to risks generally affecting the energy industry. To partially mitigate our risks, we have a system of standards, practices and procedures to identify, assess and mitigate safety, operational and environmental risk across our operations. In addition, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations. However, there can be no assurance as to the amount, if any, or timing of recovery under our insurance policies in connection with losses associated with these events and risks. Although we maintain insurance for a number of risks and hazards, we may not be insured or fully insured against all losses or liabilities that could arise from our assets or operations.

 

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Health and Safety

The operation of our properties is subject to hazards of finding, recovering, transporting, refining, processing and marketing hydrocarbons including, but not limited to: blowouts; fires; explosions; railcar incident or derailment; gaseous leaks; migration of harmful substances; loss of containment; releases or spills, including releases or spills from shipping vessels at terminals or hubs and as a result of pipeline or other leaks; corrosion; epidemics or pandemics; and catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, acts of vandalism and terrorism; and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites. Any of these hazards can interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology systems, related data and control systems, cause environmental damage that may include polluting water, land or air, and may result in fines, civil suits, or criminal charges against Cenovus, any of which may have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation.

Aviation Incidents

Cenovus’s Offshore operations in Canada and China rely on regular travel by helicopter. A helicopter incident resulting in loss of life, facility shutdown or regulatory action could have a material adverse effect on our operations. This risk is managed through an aviation management process. Aviation Safety Reviews are conducted by third party specialist contractors to verify that helicopter service providers meet Cenovus’s and industry standards with respect to aviation safety. The reviews include evaluation of aircraft type, effectiveness of the safety and maintenance management systems and competency and training programs for critical roles in the operation of helicopters. Helicopters chartered to support Offshore operations must be fit for service and as such are fitted with multiple redundant systems to address a wide range of potential in-flight emergencies. Additional measures specific to our challenging operating environments are specified in our design requirements including anti-icing and floatation systems effective for the maximum allowable sea height operating limits. Pilots are trained to address potential emergency situations through regular real-time and simulator training aligned with industry best practice.

Ice Management

Although extensive measures are in place to prevent incidents related to sea ice and icebergs, our offshore operations are at risk of incidents caused by icebergs which may interrupt operations, impact our reputation, cause loss of life, personal injury, or damage to equipment or the environment, and may result in regulatory action or litigation against us. We have several policies in place to protect people, equipment and the environment in the event of extreme weather conditions and adverse ice conditions. We have developed Adverse Weather Guidelines for the SeaRose floating production, storage and offloading vessel and continue to manage physical risk through engineering for extreme weather events.

Our Atlantic operations have a robust ice management program, which uses a range of resources including an industry shared ice surveillance aircraft, as well as synergistic relationships with government agencies including Environment and Climate Change Canada, the Canadian Coast Guard and Canadian Ice Service. In addition, Atlantic operators employ a series of supply and support vessels to actively manage ice and icebergs. We also maintain a series of relationships with contractors on a stand-by basis, allowing the quick mobilization of additional resources as required. We regularly assess all aspects of our ice management program in order to ensure that the program continues to evolve as more information about the characteristics of ice and icebergs becomes available and as new technologies are developed.

Market Access Constraints and Transportation Restrictions

Our production is transported through various pipelines, marine and rail networks and our refineries are reliant on various pipelines and rail networks to receive feedstock. Disruptions in, or restricted availability of, pipeline service and/or marine or rail transport, could adversely affect crude oil, refined products and natural gas sales, projected production growth, upstream or refining operations and cash flows.

Interruptions or restrictions in the availability of these pipeline, marine and rail systems may also limit the ability to deliver production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our products. These interruptions and restrictions may be caused by, among other things, the inability of the pipeline, marine or rail networks to operate, or may be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. There can be no certainty that investments in new pipeline projects, which would result in an increase in long-term takeaway capacity, will be made by applicable third party pipeline providers that any applications to expand capacity will receive the required regulatory approval, or that any such approvals will result in the construction of the pipeline project or that such projects would provide sufficient transportation capacity and access to refining capacity. There is also no certainty that short-term operational constraints on the pipeline system, arising from pipeline interruption and/or increased supply of crude oil, will not occur.

There is no certainty that crude-by-rail, marine transport and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, our crude-by-rail and marine shipments may be impacted by service delays, inclement weather, railcar availability, railcar derailment or other rail or marine transport incidents and could adversely impact crude oil sales volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal

 

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injury, loss of equipment or property, or environmental damage. In addition, rail and marine regulations are constantly being reviewed to ensure the safe operation of the supply chain. Should regulations change, the costs of complying with those regulations will likely be passed on to rail and/or marine shippers and may adversely affect our ability to transport crude-by-rail and/or marine transport or the economics associated with rail transportation. Finally, planned or unplanned shutdowns or closures of our refineries or of our refinery customers may limit our ability to deliver product with negative implications on sales and cash from operating activities.

Operational Considerations

Our operations are subject to all of the risks normally incidental to: (i) the storing, transporting, processing, and marketing of crude oil, refined products, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; (iii) the operation and development of crude oil and natural gas properties; and (iv) the operation of refineries, terminals, pipelines and other transportation and distribution facilities. These risks include but are not limited to: encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; explosions; blowouts; loss of containment; gaseous leaks; power outages; migration of harmful substances into water systems; oil spills; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or operate within established operating parameters; adverse weather conditions; pollution; freeze-ups and other similar events; the breakdown or failure of equipment, pipelines and facilities, information systems and processes; the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects); releases or spills from offshore operations, shipping vessels or other marine transport incidents; railcar incidents or derailments; failure to maintain adequate supplies of spare parts; the compromise of information technology and control systems and related data; operator error; labour disputes; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries, which may prevent the full utilization of the Company’s facilities and pipelines; spills at truck terminals and hubs; spills associated with the loading and unloading of potentially harmful substances onto trucks; loss of product; unavailability of feedstock; price and quality of feedstock; epidemics or pandemics; and catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, acts of sabotage and other similar events.

Producing and refining oil, bitumen and diluted bitumen requires high levels of investment and involves particular risks and uncertainties. Our oil sands operations are susceptible to reduced production, slowdowns, shutdowns, or restrictions on our ability to produce higher value products due to the interdependence of our component systems. Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production.

We do not insure against all potential occurrences and disruptions in respect of our assets or operations, and it cannot be guaranteed that our insurance coverage will be available or sufficient to fully cover any claims that may arise from such occurrences or disruptions. Our operations could also be interrupted by natural disasters or other events beyond our control. The occurrence of an event that is not fully covered by our insurance program could have a material adverse effect on our business, financial condition, results of operation and cash flows.

Reserves Replacement and Reserve Estimates

If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves.

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including, but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes, and environmental and emissions related regulations and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary materially from estimated results.

All such estimates are to some degree uncertain and classifications of reserves are only attempting to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material.

Estimates with respect to reserves that may be developed and produced in the future are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history.

 

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Subsequent evaluation of the same reserves based on production history will result in variations, which may be material, in the estimated reserves.

The production rate of oil and gas properties tends to decline as reserves are depleted while the associated operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on schedule; and the application of successful exploitation techniques on mature properties. Our business, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves.

Cost Management

Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and additional government or environmental regulations. Our inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on our financial condition, results of operations and cash flows.

The cost or availability of oil and gas field equipment may adversely affect our ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including drilling rigs, geological and geophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices. Without compromising safety, overall quality and environmental impacts, we continually develop our approved suppliers base to provide undisrupted access to materials, equipment and services, while maintaining a competitive cost baseline via cost escalation mitigation strategies. A failure to secure equipment necessary to our operations for the expected price, on the expected timeline, or at all, may have an adverse effect on our financial condition, results of operations, and cash flows.

Competition

The Canadian and international energy industry is highly competitive in all aspects, including accessing capital, the exploration for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas interests and the refining, distribution and marketing of oil and gas products. We compete with other producers and refiners, some of which may have lower operating costs or greater resources than our company does. Competing producers may develop and implement recovery techniques and technologies which are superior to those we employ. The oil and gas industry also competes with other industries in supplying energy, fuel and related products to consumers, including renewable energy sources which may become more prevalent in the future.

Project Execution

Cenovus manages a variety of oil, natural gas and refining projects across its global portfolio, including the current rebuild of our Superior Refinery. The wide range of risks associated with project development and execution, as well as the commissioning and integration of new facilities with existing assets, can impact the economic viability of the Company’s projects. These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory approvals; our ability to obtain favourable terms or to be granted access within land-use agreements; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy of project cost estimates; our ability to finance capital and expenses; our ability to source or complete strategic transactions; the effect of COVID-19 on project execution and timelines; and the effect of changing government regulation and public expectations in relation to the impacts of oil and gas operations on the environment. The commissioning and integration of new facilities within our existing asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows and may affect our safety and environmental record thereby negatively affecting our reputation and social license to operate.

Partner Risks

Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures. Therefore, our results of operations and cash flows may be affected by the actions of third-party operators or partners and our ability to control and manage risks may be reduced. We rely on the judgment and operating expertise of our partners in respect of the operation of such assets and to provide information on the status of such assets and related results of operations; however, we are, at times, dependent upon our partners for the successful execution of various projects.

Our partners may have objectives and interests that do not align with or may conflict with our interests. No assurance can be provided that the future demands or expectations of Cenovus relating to such assets will be satisfactorily met in a timely manner or at all. If a dispute with a partner or partners were to occur over the development and operation of a project or if a partner or partners were unable to fund their contractual share of

 

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the capital expenditures, a project could be delayed and Cenovus could be partially or totally liable for its partner’s share of the project.

SAGD Technology

Current technologies used for the recovery of bitumen can be energy intensive, including SAGD which requires significant consumption of natural gas in the production of steam used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using SAGD technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial condition, results of operations and cash flows. There are risks associated with growth and other capital projects that rely largely or partly on new technologies, the incorporation of such technologies into new or existing operations and acceptance of new technologies in the market. The success of projects incorporating new technologies cannot be assured.

Information Systems

We rely heavily on information technology, such as computer hardware and software systems, to properly operate our business. In the event we are unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data.

In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary business information and personal information of our employees and third parties. Despite our security measures, our information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or cyberterrorists or breaches due to employee error, malfeasance or other disruptions, including natural disasters and acts of war. Any such breach could compromise information used or stored on our systems and/or networks and result in the loss, theft or exposure of confidential information related to retail credit card information, personnel files, exploration activities, corporate actions, executive officer communications and financial results. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative consequences, including damage to our reputation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

There is also a risk of cyber-related fraud whereby perpetrators attempt to take control of electronic communications or attempt to impersonate internal personnel or business partners to divert payments and financial assets to accounts controlled by the perpetrators. If a perpetrator is successful in bypassing Cenovus’s cyber-security measures and business process controls, such cyber-related fraud could result in financial losses, remediation and recovery costs, and an adverse reputational impact.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact our personnel, which could result in injury, death, extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack or activist incident targeted at a facility, terminal, pipeline, rail network, office or offshore vessel/installation owned or operated by Cenovus or any of our partners could result in the interruption or cessation of key elements of our operations. Outcomes of such incidents could have a material adverse effect on our results of operations, financial condition and business strategy. The risk to employees and board members due to ongoing social unrest in Hong Kong is being managed through reduced travel and increased awareness and monitoring of the situation. The potential for detention and/or incarceration of our employees/contractors entering or working in China remains, and as a result, review and reconsideration for travel into China has become a business/corporate process.

Leadership and Talent

Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our talent. If we are unable to retain key personnel and critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our financial condition, results of operations and pace of growth.

Litigation

From time to time, we may be the subject of demands, disputes and litigation arising out of our operations. Claims under such litigation may be material or may be indeterminate. Various types of claims may be made including, without limitation, failure to comply with applicable laws and regulations, environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, derivative actions, patent infringement and employment-related matters. We may be required to incur significant expenses or devote significant resources in defense against any such litigation, which could result in an unfavourable decision, including fines, sanctions, monetary damages, temporary suspensions of operations, or the inability to engage in certain operations or transactions. The outcome of such claims can be difficult to assess or quantify and may have a material adverse effect on our reputation, financial condition and results of operations. In

 

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addition, we may be subject to or impacted by climate change related litigation. See “Climate Change Related Litigation” for discussion.

Indigenous Land and Rights Claims

Opposition by Indigenous groups to conduct our operations, development or exploratory activities in any of the jurisdictions in which we conduct business may negatively impact us in terms of public perception, diversion of Management’s time and resources, legal and other advisory expenses, and could adversely impact our progress and ability to explore and develop properties.

Some Indigenous groups have established or asserted Indigenous treaty, title and rights to portions of Canada. There are outstanding Indigenous and treaty rights claims, which may include Indigenous title claims, on lands where we operate, and such claims, if successful, could have a material adverse impact on our operations or pace of growth. No certainty exists that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims.

The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of ongoing litigation. The fulfillment of the duty to consult Indigenous people and any associated accommodations may adversely affect our ability to, or increase the timeline to, obtain or renew, permits, leases, licences and other approvals, or to meet the terms and conditions of those approvals. In addition, the federal government has introduced legislation to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). Other Canadian jurisdictions have also introduced or passed similar legislation, or begun considering the principles and objectives of UNDRIP, or may do so in the future. The means and timelines associated with UNDRIP’s implementation by government is uncertain; additional processes may be created or legislation amended or introduced associated with project development and operations, further increasing uncertainty with respect to project regulatory approval timelines and requirements.

Regulatory Risk

The oil and gas industry and refining industry in general and our operations in particular are subject to regulation and intervention under federal, provincial, territorial, state and municipal legislation in the countries in which we conduct operations, development or exploratory activities in matters such as, but not limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government fees; production rates; environmental protection controls; protection of certain species or lands; provincial and federal land use designations; the reduction of greenhouse gases (“GHGs”) and other emissions; the export of crude oil, natural gas and other products; the transportation of crude-by-rail or marine transport; the awarding or acquisition of exploration and production, oil sands or other interests; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possibly expropriation or cancellation of contract rights. The implementation of new regulations or the modification of existing regulations could impact our existing and planned projects or increase capital investment, operating expenses or compliance costs, which could adversely impact our financial condition, results of operations and cash flows.

Regulatory Approvals

Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that we will be able to obtain all necessary licences, permits and other approvals that may be required to carry out certain exploration, development and operating activities on our properties. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder and Indigenous consultation, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; environmental and habitat assessments; and other commitments or obligations. Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs.

Abandonment and Reclamation Cost Risk

Cenovus is subject to oil and gas asset abandonment, reclamation and remediation (“A&R”) liabilities for our operations, development and exploratory activities, including those imposed by regulation under federal, provincial, territorial, state and municipal legislation in the countries in which we conduct operations, development or exploratory activities.

In Alberta, the A&R liability regime includes the Orphan Well Fund, which is administered by the Orphan Well Association (the “OWA”). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including Cenovus, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites in Alberta. The aggregate value of the A&R liabilities assumed by the OWA has increased in recent years and will remain at elevated levels until a significant number of orphaned wells are decommissioned by the OWA. In June of 2020, the OWA’s powers were expanded to more effectively manage and

 

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accelerate the clean-up of orphaned wells and associated infrastructure. For instance, in certain circumstances the OWA would be allowed to act as an operator and take over production of abandoned wells. While the Alberta Energy Regulator’s (“AER’s”) Site Rehabilitation Program is funding up to $1 billion of eligible abandonment and reclamation projects through December 31, 2022, it is uncertain how this program, or the recent expansion of the OWA’s capabilities, will impact future orphan well liabilities being placed on the OWA. The OWA may seek additional funding for such liabilities from industry participants, including Cenovus.

The AER has broad discretion relating to liability management ratings, licence eligibility and licence transfers. Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within their asset bases, may be negatively affected by increased financial requirements, including potential counterparties to Cenovus. This may result in future insolvencies and additional orphaned assets. In addition, this may impact Cenovus’s ability to transfer our licences, approvals or permits, and may result in increased costs and delays or require changes to or abandonment of projects and transactions.

Cenovus has an ongoing environmental monitoring program at owned and leased retail locations and performs remediation where required. The costs of such remediation depend on a number of uncertain factors such as the extent and type of remediation required. Due to uncertainties inherent in the estimation process, it is possible that existing estimates may need to be revised and that conditions may exist at various retail locations that require future expenditures. Such future costs may not be determinable due to the unknown timing and extent of corrective actions that may be required.

For Offshore, the present value cost for decommissioning and abandonment of the offshore wells and facilities is estimated based on known regulations, procedures and costs today for undertaking the decommissioning, the majority of which is projected to be incurred in the 2030s. It is possible that these costs may change materially before decommissioning due to regulatory changes, technological changes, acceleration of decommissioning timelines, and inflation among other variables.

While the impact on Cenovus of any legislative, regulatory or policy decisions relating to the A&R liability regulatory regime in the jurisdictions in which we conduct operations, development or exploratory activities cannot be reliably or accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows.

Royalty Regimes

Our cash flows may be directly affected by changes to royalty regimes. The governments of the jurisdictions where we have producing assets receive royalties on the production of hydrocarbons from lands in which they respectively own the mineral rights and which Cenovus produces under agreement with each respective government. Government regulation of royalties is subject to change for a number of reasons, including, among other things, political factors. In Canada, there are certain provincial mineral taxes payable on hydrocarbon production from lands other than Crown lands. The potential for changes in the royalty and mineral tax regimes applicable in the jurisdictions in which Cenovus operates, or changes to how existing royalty regimes are interpreted and applied by the applicable governments, creates uncertainty relating to the ability to accurately estimate future royalty rates or mineral taxes and could have a significant impact on our business, financial condition, results of operations and cash flows. An increase in the royalty rates or mineral taxes in jurisdictions where we have producing assets would reduce our earnings and could make, in the respective jurisdiction, future capital expenditures or existing operations uneconomic. A material increase in royalties or mineral taxes may reduce the value of our associated assets.

Canada-United States-Mexico Agreement (“CUSMA”)

On July 1, 2020, the new CUSMA entered into force, replacing the North American Free Trade Agreement (“NAFTA”). According to a Government of Canada technical summary of negotiated outcomes related to the energy sector, under CUSMA, the rule of origin applicable to heavy oil containing diluent has been relaxed to allow up to 40 percent of non-originating diluent that is added for the purpose of transportation in pipelines without affecting the originating status of the product, which will allow Canadian products to more easily qualify for duty-free treatment when imported into the U.S. The related CUSMA side letter on energy between Canada and the U.S. also promotes regulatory transparency and non-discrimination in access to or use of energy infrastructure, which may potentially benefit the Canadian heavy oil industry. While it is not yet known how certifications can be successfully substantiated, this is an improvement to the NAFTA origin rule.

The investor-state dispute settlement provisions will no longer be available to protect future investments of Canadians in the U.S. or U.S. investments in Canada. For three years after the termination of NAFTA, existing “legacy investments” will maintain their access to the investor-state dispute settlement under NAFTA Chapter 11.

Labour Risk

Cenovus depends on unionized labour for the operation of certain facilities and may be subject to adverse employee relations and labour disputes, which may disrupt operations at such facilities. As of February 1, 2021, approximately 6.1 percent of our employees were represented by unions under existing collective bargaining agreements with Cenovus’s newly acquired operating subsidiaries. We cannot assure that strikes or work

 

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stoppages will not occur. Any prolonged work stoppages may have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows.

In addition, we may not be able to renew or renegotiate our subsidiaries’ collective bargaining agreements on satisfactory terms or at all and a failure to do so may increase our costs. Moreover, employees who are not currently represented by unions may seek union representation in the future and efforts may be made from time to time to unionize other portions of our workforce. Any renegotiation of our existing collective bargaining agreements may result in terms that are less favourable to Cenovus, which may materially and adversely affect our financial condition, results of operations and cash flows.

Future unionization efforts or changes in legislation and regulations may result in labour shortages, higher labour costs, as well as wage, benefit, and other employment consequences, especially during critical maintenance and construction periods, all of which may increase our costs, reduce our revenues or limit our operational flexibility.

International Developments and Geopolitical Risk

Cenovus’s business includes Asia Pacific Assets in the South China Sea and the Madura Strait offshore Indonesia, and includes cooperation agreements with China National Offshore Oil Corporation or its subsidiaries (collectively “CNOOC”), which also operates certain of these assets.

As a result, Cenovus is exposed to the financial and operational risks associated with uncertain international relations. Political developments impacting international trade, including trade disputes and increased tariffs, particularly between the U.S. and China and Canada and China, may negatively impact markets and cause weaker macroeconomic conditions or drive political or national sentiment, weakening demand for crude oil, natural gas and refined products. For example, U.S. government trade policy has resulted in, and could result in more, U.S. trading partners adopting responsive trade policy and may make it more difficult or costly for Cenovus to operate in and export our products to those countries.

Moreover, our operations may be materially adversely affected by political, economic or social instability or events, including the renegotiation or nullification of agreements and treaties, the imposition of onerous regulations, embargoes, sanctions, and fiscal policy, changes in laws governing existing operations, financial constraints, including currency restrictions and exchange rate fluctuations, unreasonable taxation and the behaviour of international public officials, joint venture partners or third-party representatives. Specifically, our Asia Pacific assets expose Cenovus to the effects of the changing U.S.-China and Canada-China relations, including escalating tensions and possible retaliations. It is possible that additional actions taken by the U.S. and Canada may limit or restrict foreign companies’ ability to participate in projects and operate in certain sectors of the Chinese economy, including the energy sector.

On November 12, 2020, the former President of the United States signed an executive order prohibiting U.S. persons from engaging in transactions in the publicly traded securities of specified companies with alleged ties to the Chinese military. The prohibition is intended to be effective from January 11, 2021 to November 21, 2021. On December 3, 2020, CNOOC was added to the list of companies with alleged ties to the Chinese military. Although the executive order does not limit Cenovus’s offshore operations in Asia, further U.S. sanctions against CNOOC may affect such operations, depending on the nature of such sanctions.

A new U.S. presidential administration took office in January 2021 and may implement domestic and foreign policy that could have a significant impact on Cenovus’s financial condition or results of operations. We cannot accurately predict the implementation of U.S. or Canadian policy affecting any current or future activities by CNOOC, Cenovus’s other international partners or Cenovus. Similarly, we cannot accurately predict whether U.S. restrictions will be further tightened or the impact of government action on Cenovus’s offshore operations in Asia. It is possible that the U.S. or Canadian government may subject CNOOC or Cenovus’s other international partners to restrictions or sanctions, which may adversely impact our offshore operations in Asia.

Moreover, it is possible that our partnership with CNOOC may deter certain investors from investing in Cenovus, or encourage certain investors to divest their existing holdings in Cenovus, which could have a negative impact on our share price and our ability to raise capital. It is also possible that as a result of our partnership with CNOOC, we may be subject to negative media attention which may affect investors’ perception of Cenovus in Canada, the U.S. and globally, and which may negatively affect our share price.

In addition, Cenovus may be affected by changes to bilateral relationships, the frameworks and global norms that govern international trade, and other geopolitical developments. This includes acute shocks (such as civil unrest or sanctions) and chronic stresses (such as political or business disputes and other forms of conflict, including military conflict) that may pose longer-term threats to our business. Unilateral action by, or changes in relations between, countries in which we operate, including the U.S. and China, and such countries’ approach to multilateralism and trade protectionism can impact our ability to access markets, technology, talent and capital. Disruptions or unanticipated changes of this nature may affect our ability to sell our products for optimum value or access inputs required for effective operations and has the potential to adversely affect our financial performance.

Geopolitical events, such as a shift in the relationship, an escalation or imposition of sanctions, tariffs or other trade tensions between the U.S. and China and Canada and China, may affect the supply, demand and price of crude oil, natural gas and refined products and therefore our financial performance. The timing, extent and fallout

 

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of the ongoing tensions between the U.S. and China and Canada and China remains uncertain and the impact on our business is unknown.

Shifts in global power relations may also introduce greater uncertainty with respect to issues requiring global co-ordination (such as climate change, trade agreements, tax regulation, freedom of navigation and technology regulation), as well as raise questions on the efficacy of and trust in international institutions, including those that underpin international trade. These types of changes may cause restrictions or impose costs on our business, and may inhibit our future opportunities or affect our financial condition.

Cenovus’s financial performance, operations and business may be adversely affected by any of the foregoing risks associated with international relations and specifically those risks arising from evolving U.S.-China and Canada-China relations. The nature, extent and magnitude of the effect of dynamic trade relations on Cenovus cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, results of operations, cash flows, and reputation.

Climate-Related Risks

There is growing international concern regarding climate change and there has been a significant increase in focus on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, environmental and governance organizations, institutional investors, social and environmental activists, and individuals, are increasingly seeking to implement, among other things, regulatory and policy changes, changes in investment patterns, and modifications in energy consumption habits and trends which, individually and collectively are intended to or have the effect of accelerating the reduction in the global consumption of carbon-based energy, the conversion of energy usage to less carbon-intensive forms and the general migration of energy usage away from carbon-based forms of energy.

Climate change and its associated impacts may increase our exposure to, and magnitude of, each of the risks identified in the Risk Management and Risk Factors section of this MD&A. Overall, Cenovus is not able to estimate at this time the degree to which climate change related regulatory, climatic conditions, and climate-related transition risks could impact the Company’s financial and operating results. Our business, financial condition, results of operations, cash flows, reputation, access to capital, access to insurance, cost of borrowing, access to liquidity, ability to fund dividend payments and/or business plans may, in particular, without limitation, be adversely impacted as a result of climate change and its associated impacts.

Transition Risks – Policy & Legal

Climate Change Regulation

Cenovus operates in several jurisdictions that regulate or have proposed to regulate air pollutants, including GHG emissions. Some of these regulations are in effect while others remain in various phases of review, discussion or implementation. Uncertainties exist relating to the timing and effects of these emerging regulations, other contemplated legislation, including how they may be harmonized, making it difficult to accurately determine the cost impacts and effects on our suppliers. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time. In December 2020, the Government of Canada proposed increasing the carbon tax to $170/tonne carbon dioxide equivalent (“CO2e”) by 2030. To reach that level, the price imposed on carbon will rise from the 2022 rate of $50/tonne CO2e by $15/tonne CO2e each year until 2030. If made into law, this may have a significant impact on Cenovus. Notably, several Canadian provinces have launched constitutional challenges to Canada’s national carbon-pricing regime that were heard by the Supreme Court of Canada (“SCC”) in September 2020; however, as of December 31, 2020, the SCC’s decision had not yet been issued. To the extent a province’s carbon pricing system does not meet the federal stringency requirements, the federal “backstop” price of carbon applies. As of December 2020, the federal backstop applied in Alberta, Manitoba, New Brunswick, Ontario and to electricity generation and natural gas transmission pipelines in Saskatchewan.

In Alberta, facilities emitting over 100,000 tonnes of GHG emissions annually are subject to the Technology Innovation and Emissions Reductions Regulation (“TIER”), which is considered equivalent to the federal carbon-pricing system for 2020. Facilities also have the choice to opt in to TIER, thereby avoiding the federal fuel charge.

The Government of Canada is also committed to reducing methane emissions from the crude oil and natural gas sector by 40-45 percent from 2012 levels by 2025. Regulatory requirements for fugitive equipment leaks and venting from well completion and compressors came into force on January 1, 2020. Further restrictions on facility production venting restrictions and venting limits for pneumatic equipment come into force on January 1, 2023. Provinces may introduce provincial regulations, and if found to be at least equivalent with the federal scheme, shall be enabled through a federal equivalency agreement process. Alberta, British Columbia and Saskatchewan have such equivalency agreements in place.

The U.S. does not have federal legislation establishing targets for the reduction of, or limits on, GHG emissions. However, the federal Environmental Protection Agency (“EPA”) has and may continue to promulgate regulations concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program (“GHGRP”) requires any facility releasing more than 25,000 tonnes of CO2e emissions per year to report those emissions on an annual basis. In addition to reporting direct CO2e emissions, the GHGRP requires refineries to

 

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estimate the CO2e emissions from the potential subsequent combustion of the refinery’s products. The Biden Administration has indicated that it will rejoin the Paris Agreement and seek to implement its objectives with respect to GHG emissions, including short-term global emissions reductions and net-zero global emissions by mid-century, and that it will begin the process of developing U.S. emission reduction targets under the Paris Agreement. It is too early to assess what impact these actions may have on our business, financial condition or results of operations.

Negative consequences which could arise as a result of changes to the current regulatory environment include, but are not limited to, changes in environmental and emissions regulation of current and future projects by governmental authorities, which could result in changes to facility design and operating requirements, potentially increasing the cost of construction, operation and abandonment. Other possible effects from emerging regulations may also include, but are not limited to: increased compliance costs; permitting delays; and substantial costs to generate or purchase emission credits or allowances, all of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be available on an economic basis, required emissions reductions may not be technically or economically feasible to implement, in whole or in part, and failure to have access to resources or technology to meet emissions reduction requirements or other compliance mechanisms may have a material adverse effect on our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations.

The extent and magnitude of any adverse impacts of current or additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time, in part because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the timeframes for compliance. Consequently, no assurances can be given that the effect of future climate change regulations will not be significant to Cenovus.

Low Carbon Fuel Standards

Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian provinces, the Canadian federal government and members of the European Union, regulating carbon fuel standards could result in increased costs and reduced revenue for Cenovus. The potential regulation may negatively affect the marketing of Cenovus’s bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to affect sales in such jurisdictions.

Environment and Climate Change Canada published a proposed regulatory framework in 2017 for the Clean Fuel Standard under the Canadian Environmental Protection Act, 1999, followed by a Regulatory Design Paper in December 2018 and a Proposed Regulatory Approach in June 2019. The proposed regulations for the Clean Fuel Standard were published in December 2020 and final regulations are planned to be published in late 2021, with new regulations under the Clean Fuel Standard targeted to come into force in 2022. The federal government has indicated that over time, the new Clean Fuel Standard would replace the current Renewable Fuels Regulations, which currently require producers and importers of gasoline, diesel fuel and heating distillate to acquire a certain number of renewable fuel compliance units commensurate with the volumes of fuel they produce or import. The proposed new regulatory framework would impose lifecycle carbon intensity requirements for certain liquid fuels and establish rules relating to the trading of compliance credits. Carbon intensity requirements under the Clean Fuel Standard regulation would become more stringent over time and would be differentiated between different types of renewable fuels to reflect the associated emissions reduction potential. Regulated parties, which may include fuel producers and importers, would have some flexibility with respect to how to achieve lower carbon fuels in Canada.

The Clean Fuel Standard regulation has the potential to impact our business, financial condition, results of operations and cash flows, though at this time it is difficult to predict or quantify any such impacts.

Renewable Fuel Standards

Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. The Environmental Protection Agency has implemented the Renewable Fuel Standard program that mandates that a certain volume of renewable fuel replace or reduce the quantity of certain petroleum-based transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of gasoline or diesel fuel, achieve compliance with targets set by the U.S. Environmental Protection Agency by blending certain types of renewable fuel into transportation fuel, or by purchasing RINs from other parties on the open market. The mandate requires the volume of renewable fuels blended into finished petroleum products to increase over time until 2022. A RIN is a number assigned to each gallon of renewable fuel produced or imported into the U.S. RINs were implemented to provide refiners with flexibility in complying with the renewable fuel standards.

Cenovus and its refinery operating partners comply with the U.S. Renewable Fuel Standard by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market, where prices fluctuate. The Company cannot predict the future prices of RINs and renewable fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. The Company’s financial position, results of operations and cash flows may be materially impacted if we are required to pay significantly higher prices for RINs or blendstocks to comply with the RFS mandated standards and are unable to pass the compliance costs on to our customers.

 

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Climate Change Related Litigation

In recent years there has been an increase in climate change related demands, disputes, and litigation in various jurisdictions including the U.S. and Canada, asserting various claims, including that energy producers contribute to climate change, that such entities are not reasonably managing business risks associated with climate change, and that such entities have not adequately disclosed business risks of climate change. While many of the climate change related actions are in preliminary stages of litigation, and in some cases assert novel or untested causes of action, there can be no assurance that legal, societal, scientific and political developments will not increase the likelihood of successful climate change related litigation against energy producers, including Cenovus. The outcome of any such litigation is uncertain and may materially impact our financial condition or results of operations. Moreover, unfavourable outcomes or settlements of litigation could encourage the commencement of additional litigation. We may also be subject to adverse publicity associated with such matters, which may negatively affect public perception and our reputation, regardless of whether we are ultimately found responsible. We may be required to incur significant expenses or devote significant resources in defense against any such litigation.

Transition Risks – Market

Demand and Commodity Prices

The recent increase in focus on the timing and pace of the transition to a lower-carbon economy and resulting trends will likely affect global energy demand and usage, including the composition of the types of energy generally used by industry and individual consumers. However it is not currently possible to predict the timelines for and precise effects of this transition to a potential lower-carbon economy, which will depend on a multitude of factors including the ability to develop adequate replacement sources of energy, technology development and adaptation including in the area of transportation electrification, the ability to conceptualize, develop and commercialize technologies for the production, storage and distribution of adequate supplies of alternative energy, consumption patterns, global growth and industrial activity, in order to predict the longer-term demand trends for carbon-based energy sources. All of these factors are beyond our control and could result in a high degree of price volatility for each of crude oil, natural gas and refined products.

Access to Capital and Insurance

Capital markets are adjusting to the risks that climate change poses and as a result, our ability to access capital and secure necessary or prudent insurance coverage may also be adversely affected in the event that institutional investors, credit rating agencies, lenders and/or insurers adopt more restrictive decarbonization policies. Certain insurance companies have taken actions or announced policies to limit available coverage for companies which derive some or all of their revenue from the oil sands sector. As a result of these policies, premiums and deductibles for some or all of our insurance policies could increase substantially. In some instances, coverage may be reduced or become unavailable. As a result, we may not be able to renew our existing policies, or procure other desirable insurance coverage, either on commercially reasonable terms, or at all. The future development of our business may be dependent upon our ability to obtain additional capital, including debt and equity financing.

Transition Risks – Reputation

Reputation and Public Perception of Alberta Oil Sands

Development of the Alberta oil sands has received considerable attention on the subjects of environmental impact, climate change, GHG emissions and Indigenous engagement. Concerns about oil sands may, directly or indirectly, impair the profitability of our current oil sands projects, and the viability of future oil sands projects, by creating significant regulatory, economic and operating uncertainty. Increased public opposition to the oil sands industry could lead to constrained access to insurance, liquidity and capital and changes in demand for Cenovus’s products, which may impact revenue.

For example, legislation or policies that limit the purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or foreign jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in stranded assets or an inability to further develop oil resources.

Climate Change – Physical Risks

Extreme climatic conditions may also have material adverse effects on Cenovus’s financial condition and results of operations. Weather and climate affect demand, and therefore, the predictability of the demand for energy is affected to a large degree by the predictability of weather and climate. In addition, Cenovus’s exploration, production and construction operations, and the operations of major customers and suppliers, can be affected by floods, forest fires, earthquakes, hurricanes, and other extreme weather events. This may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction.

Cenovus operates in some of the harshest environments in the world, including offshore Newfoundland and Labrador. Climate change may increase the frequency of severe weather conditions in these locations including winds, flooding and variable temperatures, which are contributing to the melting of northern ice and increased creation of icebergs. Icebergs off the coast of Newfoundland and Labrador may threaten Atlantic oil production facilities, cause spills, damage assets, disrupt production or have human impacts.

 

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Our other crude oil and natural gas production activities are also subject to chronic physical risks such as a shorter timeframe for our winter drilling program, changes in the water table and reduced access to water due to drought conditions. A systemic change in temperature or precipitation patterns could result in more challenging conditions for the construction of ice roads, execution of our winter drilling program and reclamation activities and could reduce the availability of water due to the increasing likelihood of drought conditions.

Environmental Risk

All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a variety of federal, provincial, territorial, state and municipal laws and regulations in the jurisdictions in which we operate (collectively, the “environmental regulations”). Environmental regulations provide that wells, facility sites, refineries and other properties and practices associated with our operations be constructed, operated, maintained, abandoned, reclaimed and undertaken in accordance with the requirements set out therein. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications.

Cenovus anticipates that further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, increased compliance costs and approval delays for critical licences and permits. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to Cenovus.

Compliance with environmental regulations requires significant expenditures. Our future capital expenditures and operating expenses could continue to increase as a result of, among other things, developments in our business, operations, plans and objectives and changes to existing, or implementation of new, environmental regulations. Failure to comply with environmental regulations may result in, among other things, the imposition of fines, penalties, environmental protection orders, suspension of operations, and could adversely affect our reputation. The costs of complying with environmental regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows. The implementation of new environmental regulations or the modification of existing environmental regulations affecting the crude oil and natural gas industry generally could reduce demand for crude oil and natural gas as well as shift hydrocarbon demand toward relatively lower carbon sources, increase compliance costs, lengthen project implementation times, and have an adverse effect on our business, financial condition, results of operations and cash flows.

Canadian Species at Risk Act

The Canadian federal Species at Risk Act, as well as provincial regulation regarding threatened or endangered species and their habitat may limit the pace and the amount of development or activity in areas identified as critical habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal government in relation to their obligations under the Species at Risk Act have raised issues associated with the protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, a suite of initiatives have been undertaken to support caribou recovery, including the Draft Provincial Woodland Caribou Range Plan, which was released in 2017 but has not yet been finalized. Other initiatives include negotiation of conservation agreements under Section 11 of the Species at Risk Act (which codifies concrete measures to support the conservation of the species and the protection of its critical habitat), and the elaboration of sub-regional plans for the Cold Lake, Bistcho and Upper Smokey areas, to address recovery outcomes for certain caribou ranges. If plans and actions undertaken by the provinces are deemed insufficient to support caribou recovery, the federal legislation includes the ability to implement measures that would preclude further development or modify existing operations. The extent and magnitude of any potential adverse impacts of legislation on in situ oil sands project development and operations cannot be estimated, as uncertainty exists as to whether plans and actions undertaken by the provinces will be sufficient to support caribou recovery.

Canadian Federal Air Quality Management System

The Multi Sector Air Pollutants Regulations (“MSAPR”), issued under the Canadian Environmental Protection Act, 1999, seek to protect the environment and health of Canadians by setting mandatory, nationally-consistent air pollutant emission standards. The MSAPR are aimed at equipment-specific Base-Level Industrial Emissions Requirements (“BLIERs”). Nitrogen oxide BLIERs from our non-utility boilers, heaters and stationary engines are regulated in accordance with specified performance standards. We anticipate that the MSAPR will result in adverse impacts to Cenovus including but not limited to capital investment required to retrofit existing equipment and increased operating costs.

Canadian Ambient Air Quality Standards (“CAAQS”) for nitrogen dioxide, sulphur dioxide, fine particulate matter and ozone were introduced as part of a national Air Quality Management System. Provinces may implement the CAAQS at the regional air zone level and air zone management actions may include more stringent emissions standards applicable to industrial sources from approval holders in regions where Cenovus operates that may result in adverse impacts including but not limited to capital investment related to retrofit existing facilities and increased operating costs.

 

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Review of Environmental and Regulatory Processes

Increased environmental assessment obligations imposed by federal, provincial, territorial, state and municipal governments in the jurisdictions in which we conduct operations, development or exploratory activities may create risk of increased costs and project development delays. The extent and magnitude of any adverse impacts of changes to the legislation or policies on project development and operations cannot be estimated at this time.

The Canadian federal Bill C-69, an Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act (renamed the Canadian Navigable Water Act) and to make consequential amendments to other Acts came into force in August 2019. In addition, Bill C-68, which amended the Fisheries Act, came into force at the same time.

The Fisheries Act amendments restored the previous prohibition against “harmful alteration, disruption or destruction of fish habitat” and the prohibition against causing the death of fish by means other than fishing and introduced several new requirements expanding the scope of protection and role of Indigenous groups and interests. These prohibitions may result in increased permitting requirements and time to obtain permits where Cenovus’s operations potentially impact fish or fish habitat.

The Canadian Navigable Waters Act expanded its scope to all navigable waters, created greater oversight for navigable waters, and introduced requirements expanding the scope of protection and the role of Indigenous groups and interests. The broader application of the Canadian Navigable Waters Act may result in increased permitting requirements and time to obtain permits where Cenovus’s operations potentially impact navigable waters.

The Impact Assessment Act (“IAA”) established the Impact Assessment Agency of Canada, which leads and coordinates impact assessments for all designated projects. The IAA expands the assessment considerations beyond the environment to expressly include health, economic, social, and gender impacts, as well as considerations related to sustainability and Canada’s climate change commitments.

Of note, the revised Project List outlined in the Physical Activities Regulations under the IAA captures in situ oil sands facilities with a bitumen production capacity of 2,000 m3/day or more, and expansions of existing in situ oil sands facilities if the expansion would result in an increase in bitumen production capacity of 50 percent or more and a total bitumen production capacity of 2,000 m3/day or more, but provides an exemption for a project proposed within a province in which there is a legislated limit on GHG emissions produced by the oil sands sector. For as long as the provincial government maintains the cap on oil sands emissions in Alberta and the cap has not been reached, Cenovus’s in situ oil sands projects should be exempted from the application of the new federal impact assessment system, provided the above-noted conditions are met. However, other types of projects would undergo a federal assessment.

Water Licences

Cenovus utilizes fresh water in certain operations, which is obtained under licenses issued within each respective jurisdiction’s regulations. If water use fees increase or a change under these licences reduces the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial performance. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. There is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted on favourable terms. This may adversely affect our business, including the ability to operate our assets and execute development plans.

Hydraulic Fracturing

Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and suggest that additional federal, provincial, state, territorial and/or municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

In addition, some areas of British Columbia and Alberta are experiencing increasing localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been correlated with hydraulic fracturing in Western Canada, which has prompted legislative and regulatory initiatives intended to address these concerns.

The Canadian federal government and certain provincial governments continue to review certain aspects of the existing scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. The Government of British Columbia released an action plan in 2019 based on the results of its scientific review of hydraulic fracturing and related impacts on water and seismic activity, which contains a number of actions to be implemented in a phased approach that will include increased monitoring, aquifers mapping and improvements to the regulatory regime. In Alberta, the AER has implemented seismic monitoring and reporting requirements for hydraulic fracturing operations in certain zones in some active oil and gas areas of Alberta.

Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to limitations or restrictions to oil and gas development activities, operational delays, increased compliance costs, additional

 

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operating requirements, or increased third-party or governmental claims that could increase our cost of doing business as well as reduce the amount of natural gas and oil that Cenovus is ultimately able to produce from its reserves.

Cenovus ESG Focus Areas and Targets

Generally speaking, Cenovus’s ESG targets depend significantly on our ability to execute our current business strategy, related milestones and schedules, and to successfully integrate the assets of Cenovus and the assets of Husky, each of which can be impacted by the numerous risks and uncertainties associated with our business and the industry in which we operate, as outlined in the Risk Management and Risk Factors section of this MD&A. We recognize that our ability to adapt to and succeed in a lower-carbon economy will be compared against our peers. Investors and stakeholders increasingly compare companies based on ESG-related performance, including climate-related performance. Failure to achieve our ESG targets, or a perception among key stakeholders that our ESG targets are insufficient, could adversely affect our reputation and our ability to attract capital and insurance coverage.

There is also a risk that some or all of the expected benefits and opportunities of achieving the various ESG targets may fail to materialize, may cost more to achieve or may not occur within the anticipated time periods. In addition, there are risks that the actions taken by Cenovus in implementing targets and ambitions relating to ESG focus areas may have a negative impact on our existing business and operations and increase capital expenditures, which could have a negative impact on our future operating and financial results.

ESG Targets May Change Following Completion of the Arrangement

Completion of the Arrangement between Cenovus and Husky on January 1, 2021 resulted in a combination of the business activities previously carried on separately by each of Husky and Cenovus. Cenovus remains committed to world-class safety performance and ESG leadership following closing of the Arrangement. This includes completing additional analysis to set new ESG targets and ambitions for the combined business.

The ESG targets and ambitions of the combined business may not necessarily be the same as the targets or ambitions previously set by Cenovus. This is dependent, in large measure, on the completion of our review and analysis of the combined business following the completion of the Arrangement to determine whether such targets and ambitions remain appropriate for the combined business. In addition, the integration of Husky and Cenovus will require the dedication of substantial effort, time and resources on the part of management and staff of the combined company, which may divert focus from planned initiatives, including development and implementation of ESG targets and ambitions, towards other operational matters and could result in a disruption to, or delay in, the development and implementation of ESG targets and ambitions for the combined company or a shift in resources to other operational and business strategies.

The below sections include discussion of the ESG targets released by Cenovus in January 2020 which may be subject to change as a result of our determination of whether such targets and ambitions remain appropriate for the combined business.

Greenhouse Gas Emissions and Targets

Cenovus’s future results and its ability to respond to and manage transition and physical risks of climate change may depend in part on our ability to adapt and apply our business model to a lower-carbon economy and to lower scope 1 and 2 GHG emissions (see Definitions section of this MD&A). Our ability to lower scope 1 and 2 GHG emissions on both an absolute basis and in terms of intensity in our operations and our long-term ambition of reaching net-zero emissions by 2050, are subject to numerous risks and uncertainties and our actions taken in implementing such targets may also expose us to certain additional and/or heightened financial and operational risks. Furthermore, our long-term ambition of reaching net-zero emissions by 2050 is inherently less certain due to the longer timeframe and certain factors outside of our control, including the commercial application of future technologies that may be necessary for us to achieve this long-term ambition.

A reduction in GHG emissions relies on, among other things, Cenovus’s ability to develop, access and implement commercially viable and scalable emission reduction strategies and related technology and products. In addition, there are other operational risks that may hinder our ability to successfully meet our GHG emission targets and goals, including: unexpected impediments to, or effects of, the implementation of cogeneration plants at our Foster Creek and Christina Lake oil sands facilities and other investments in renewables, including in respect of available offsets and the availability and status of credit or offset for cogeneration facilities and other renewables; the effectiveness of air flue exchanges at Foster Creek and Christina Lake; our ability to electrify and otherwise adjust our operations in the Conventional segment; the unavailability of, or limited benefits from, technology that is expected to be commercially viable in the near term and their associated future benefits, including SAGD enhancement technologies, such as solvent-aided process and solvent-driven process technologies, carbon capture, utilization and storage technology and downhole technology improvements; and a failure to capture the anticipated benefits of continued technological development, industry collaboration and innovation to find solutions to reduce costs and GHG emissions intensity. In the event that we are unable to implement these strategies and technologies as planned without negatively impacting our expected operations or cost structure, or such strategies or

 

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technologies do not perform as expected, we may be unable to meet our 2050 ambition on the current timelines, or at all.

In addition, achieving our GHG 2050 ambition will require capital expenditures and Company resources, with the potential that expectations regarding the costs required to achieve these targets and ambitions differ from our original estimates and the differences may be material. Furthermore, a shift of expenditures and resources towards such targets and ambition may negatively impact our business and operations. The cost of investing in emissions-intensity reduction technologies, and the resultant change in the deployment of resources and focus, could have a negative impact on our future operating and financial results.

Our GHG emissions targets and ambitions may also be subject to change as a result of Cenovus’s determination of whether such targets and ambitions remain appropriate for the combined business.

Indigenous Engagement Target

Cenovus’s Indigenous engagement target to spend $1.5 billion with Indigenous owned or operated businesses by the end of 2030 is subject to a number of financial, operational and efficiency risks relating to actions taken in implementing such target.

In addition, a failure or delay in achieving our Indigenous engagement target may adversely affect our relationship with neighboring Indigenous businesses and communities and our broader reputation. If we are unable to maintain a positive relationship with Indigenous communities near our operations, our progress and ability to develop and operate properties in line with our current business and operational strategies may be adversely impacted.

Our Indigenous engagement target may also be subject to change as a result Cenovus’s determination of whether such a target remains appropriate for the combined business.

Land and Wildlife Target

Our land and wildlife targets are composed of the reclamation of 1,500 decommissioned well sites and $40 million in spend between 2016 and 2030 to restore more land within caribou ranges than disturbed by Cenovus’s activity. Our ability to meet this target is subject to various environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on Cenovus and limit our capacity to achieve such targets. See Abandonment and Reclamation Cost Risk above.

Financial risks including an increase in operating costs, changes to market conditions and access to additional capital, if needed, could result in our inability to fund, and ultimately meet, our land and wildlife targets on the current timelines, or at all. In addition, the development and implementation of range plans in these areas may have an impact on the pace and amount of development in these areas and could potentially increase costs for restoration or offsetting requirements, which could have a material adverse effect on our business, financial condition, reserves and results of operations. An inability to develop, execute on and complete ongoing reclamation plans and proactively manage our interactions with wildlife may adversely impact Cenovus’s progress and ability to explore and develop properties.

Our land and wildlife targets may also be subject to change as a result of Cenovus’s determination of whether such targets remain appropriate for the combined business.

Water Stewardship Target

Cenovus’s ability to achieve a freshwater intensity of 0.1 barrels of freshwater per barrel of oil equivalent by the end of 2030 will depend on the commercial viability and scalability of relevant water reduction strategies and related steam and water usage technology and products. There are risks associated with relying largely or partly on new technologies, the incorporation of such technologies into new or existing operations and acceptance of new technologies in the market. In the event we are unable to effectively and efficiently deploy the necessary technology, or such strategies or technologies do not perform as expected, achieving our stated target of reducing our water intensity could be interrupted, delayed or abandoned.

Our water stewardship targets may also be subject to change as a result of Cenovus’s determination of whether such targets remain appropriate for the combined business.

Reputation Risk

We rely on our reputation to build and maintain positive relationships with investors and other stakeholders, to recruit and retain staff, and to be a credible, trusted company. Any actions we take that influence public or key stakeholder opinions have the potential to impact our reputation which may adversely affect our share price, development plans and our ability to continue operations. There is increasing opposition from activist organizations and the public towards oil sands operations stemming from the perceived impact of the industry on the environment, climate change and GHG emissions. See Reputation and Public Perception of Alberta Oil Sands for further discussion.

 

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Other Risks

Risks Related to the Arrangement

Entry into New Business Activities

Prior to the Arrangement, Cenovus’s business was focused on the development and production of bitumen in northeast Alberta, natural gas and NGLs processing in the Conventional segment, and refining, transporting, marketing and selling crude oil, natural gas and NGLs in Canada and the U.S. Husky’s business involved upstream development and production in Western Canada, offshore China, Indonesia and Atlantic Canada, and upgrading of heavy oil, refining crude oil, and marketing refined petroleum products in Canada and the U.S. The combined company’s business comprises a combination of these businesses, which results in a different business and asset mix than the previous standalone businesses of Cenovus and Husky, respectively. The expansion of Cenovus’s activities into new geographic and operational areas as a result of the Arrangement may present additional risks or significantly increase its exposure to one or more of Cenovus’s present risk factors. The new business combination may also subject Cenovus to different business risks than those which were previously applicable to Cenovus and Husky as separate entities.

Possible Failure to Realize Anticipated Benefits of the Arrangement

Realizing the anticipated synergies from integrating the respective businesses of Cenovus and Husky depends in part on, among other things, successfully consolidating functions and integrating operations, systems, procedures and personnel in a timely and efficient manner. Achieving the benefits of the Arrangement also depends on Cenovus’s ability to effectively capitalize on its scale, scope and leadership position in the oil sands and wider oil and natural gas industry, to realize the anticipated capital and operating synergies and to maximize the potential of its improved growth and capital funding opportunities.

The integration of the Cenovus and Husky assets to realize the benefits of the Arrangement will require the dedication of substantial management effort, time and resources which may divert Cenovus’s Management’s focus and resources from other strategic opportunities and operational matters. The integration process may result in the loss of key employees and the disruption of ongoing business and employee relationships that may adversely affect Cenovus’s ability to achieve the anticipated benefits of the Arrangement. Cenovus may also incur additional expenses related to the Arrangement and the integration of Cenovus and Husky, which may limit Cenovus’s ability to realize some or all of the anticipated benefits of the Arrangement.

If Cenovus is not able to successfully achieve the synergies associated with the Arrangement, or the cost to achieve these synergies is greater than expected, the anticipated benefits of the Arrangement may not be realized fully, or at all, may take longer to realize than expected, or may result in unforeseeable adverse effects. There can be no assurance that Cenovus will be able to achieve the synergies or realize the anticipated benefits of the Arrangement in a timely manner or at all. Failing to realize the anticipated benefits of the Arrangement may adversely affect Cenovus’s financial condition, results of operations, reputation and share price.

Cenovus’s Ability to Integrate Husky’s Business with its Own

Given the increased scope and complexity of our operations, Cenovus may not be able to integrate Husky’s operations or restructure Cenovus’s previously existing business operations without encountering difficulties and delays. The integration process could result in disruption of existing relationships with suppliers, employees, customers and other constituencies of each company. Further, Cenovus will be required to maintain its financial and strategic focus while integrating Husky’s business and avoid inconsistencies in implementing uniform standards, controls, procedures and policies, as appropriate. Our ability to integrate the businesses will depend in part on our ability to access or implement some or all of the personnel and technology necessary to efficiently and effectively operate Husky’s assets. There can be no assurance that management will be able to successfully integrate the businesses to achieve any of the synergies or other benefits that are expected to result from the Arrangement.

The ongoing integration process involves numerous operational, strategic, financial, accounting, legal, tax and other risks and uncertainties associated with Cenovus’s and Husky’s business and operations. Difficulties in integrating our businesses may result in variations in expected performance, operational challenges or the failure to realize anticipated efficiencies on the expected timelines or at all. Cenovus’s and Husky’s existing businesses may also be negatively impacted by the combination.

Potential difficulties that may be encountered in the integration process include, among others: (i) the inability to successfully integrate the businesses in a manner that permits Cenovus to achieve the anticipated revenue and cost savings on the expected timelines or at all; (ii) complexities associated with managing a larger, more complex, multinational integrated business; (iii) achieving the anticipated operating synergies on the expected timelines or at all; (iv) integrating personnel at all levels of the company over multiple jurisdictions, effectively and efficiently; (v) difficulties integrating and maintaining relationships with Husky’s industry contacts and existing business partners; and (vi) the disruption of, or the loss of momentum in, each of Cenovus’s and Husky’s ongoing businesses. Such challenges may prohibit Cenovus from successfully integrating Husky’s business with its own or may materially delay the integration process. A failure to integrate the business on the expected timeline, or at all,

 

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may have an adverse effect on Cenovus’s financial condition, results of operations, and ability to realize the anticipated benefits of the Arrangement.

It is possible that the integration process could result in the loss of key employees to assist in the integration and operation of Husky and Cenovus, which may exacerbate integration challenges. Difficulties or delays in the integration process or the inability to partially or fully integrate Husky’s business with our own could have a material adverse effect on our business, cash flow, operating results, financial condition, reputation and share price.

Costs Associated with the Integration of Cenovus’s and Husky’s Businesses

Cenovus may incur significant costs related to formulating and implementing ongoing integration plans, including facilities and systems consolidation costs and other employment-related costs. Cenovus will continue to assess the magnitude of these costs and additional unanticipated costs may be incurred in connection with the integration of the two companies. While Cenovus has accounted for a certain level of expenses, many factors beyond our control may affect the total amount or the timing of expenses associated with the integration process. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not offset integration-related costs and achieve a net benefit in the near term, or at all. The costs described above and any unanticipated costs and expenses related to the integration may have an adverse effect on Cenovus’s financial condition and results of operations.

Increased Indebtedness

Cenovus’s increased indebtedness could have adverse consequences for Cenovus, including: reducing funds available for other business purposes; limiting Cenovus’s ability to obtain additional financing for working capital, capital expenditures, product development, debt service requirements, acquisitions and general corporate or other purposes; restricting Cenovus’s flexibility and discretion to operate its business; limiting Cenovus’s ability to declare dividends; having to dedicate a portion of Cenovus’s cash flows from operations to the payment of interest on its existing indebtedness and not having such cash flows available for other purposes; exposing Cenovus to increased interest expense on borrowings at variable rates; limiting Cenovus’s ability to adjust to changing market conditions; placing Cenovus at a competitive disadvantage compared with its competitors with less debt; making Cenovus more vulnerable to a downturn in general economic conditions; and reducing funds available for capital expenditures that are important to Cenovus’s business.

Dilutive Effect

The issuance of Cenovus common shares pursuant to the Arrangement had an immediate dilutive effect on the ownership interest of existing shareholders of Cenovus. The issuance of additional Cenovus common shares upon exercise, from time to time, of Cenovus Warrants or Cenovus Replacement Options issued to holders of Husky common shares and Husky options prior to the Arrangement will have a further dilutive effect on the ownership interest of shareholders of Cenovus. Such issuances will have a dilutive effect on Cenovus’s earnings per share, which could adversely affect the market price of Cenovus common shares and may adversely impact the value of Cenovus shareholders’ investments.

It is also expected that, from time to time, Cenovus will grant additional equity awards to our employees and directors under the combined Company’s compensation plans. These additional equity awards will have a further dilutive effect on Cenovus’s earnings per share, which could also negatively affect the market price of the Cenovus common shares.

Potential Undisclosed and Unforeseen Liabilities Associated with the Arrangement

In connection with the Arrangement, there may be liabilities that we failed to discover, underestimated or were unable to quantify in our due diligence conducted prior to the execution of the Arrangement Agreement and completion of the Arrangement. In addition, the Arrangement may subject Cenovus to unforeseen liabilities, including environmental and regulatory liabilities in Canada and other foreign jurisdictions. Cenovus may now be subject to claims related to Husky’s operations and previous actions, including those of its current and former directors and employees. We may also be subject to adverse publicity associated with such matters, regardless of whether we are ultimately found responsible and may be required to incur significant expenses or devote significant resources in defense against any litigation of such claims. The outcome of any such litigation is uncertain and may negatively impact our financial condition, results of operations and reputation.

Pro Forma Financial Information may not be Indicative of Cenovus’s Financial Condition or Results following the Arrangement

The pro forma financial information contained in Cenovus’s public disclosure record is presented for illustrative purposes only as of its respective dates and may not be indicative of the current financial condition or results of operations of Cenovus. The unaudited pro forma financial information was derived from the respective historical financial statements of Cenovus and Husky, and certain adjustments and assumptions were made as of such dates to give effect to the Arrangement. The information upon which these adjustments and assumptions were made was preliminary and these kinds of adjustments and assumptions are difficult to make with complete accuracy. Accordingly, the combined business, assets, results of operations and financial condition may differ significantly

 

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from those indicated in the unaudited pro forma financial information, and such variations may negatively impact our financial condition, results of operations and share price.

Pro Forma Reserves Information may not be Indicative of Cenovus’s Reserves following the Arrangement

The pro forma reserves information included in the AIF is based on the reserves reports prepared by McDaniel and GLJ for Cenovus (the “2020 Cenovus Reserves Report”), and Husky’s reserves estimates have been prepared by internal qualified reserves evaluators in accordance with the COGE Handbook, and have been audited and reviewed by Sproule, an independent qualified reserves auditor (the “2020 Husky Reserves Report”), each effective December 31, 2020 (collectively, the “2020 Reserves Reports”). The reserves information presented in each of the 2020 Reserve Reports has been aggregated by Cenovus for illustrative purposes. The 2020 Reserves Reports were prepared using different assumptions and an independent reserves report effective December 31, 2020 was not prepared for the combined company. Therefore, the actual reserves of the combined company, if evaluated as of December 31, 2020 may differ from the pro forma reserves presented in the AIF. Cenovus and Husky, as stand-alone entities, have different operational and financial capabilities, which impacts their ability to develop reserves. And finally, there are systemic differences in the future development costs for each of Cenovus and Husky.

Further, were an independent reserves evaluation to be completed on our collective reserves as a result of the Arrangement, the assumptions underlying the 2020 Husky Reserves Report may be materially different from those assumptions used to evaluate the combined company’s collective reserves. Our actual reserves could vary materially from these pro forma estimates and the Husky reserves acquired in connection with the Arrangement may be less than expected, which could adversely affect Cenovus’s business, operations, financial results and share price.

Engineering, Reserves, Economic and Environmental Assessments in connection with the Arrangement may be Inaccurate

Acquisitions of oil and natural gas properties or companies are based in large part on engineering, environmental and economic assessments made by the acquirer, independent engineers and consultants. The assessments include a series of assumptions regarding such factors as recoverability and marketability of crude oil, natural gas and refined products, environmental restrictions and prohibitions regarding releases and emissions of various substances, future commodity prices and operating costs, future capital expenditures and royalties and other government levies that may be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic, engineering, economic, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated.

Specifically, the 2020 Husky Reserves Report was prepared in respect of periods prior to completion of the Arrangement during which the crude oil and natural gas properties of Husky were operated on a stand-alone basis. Although Cenovus’s Management believes the information contained in the 2020 Husky Reserves Report is reliable, Cenovus has not independently verified the historical information contained in such report and is unable to fully assess Husky’s procedures for providing, assembling and reporting information to Sproule associated with Husky and its assets. In particular, the reserve and recovery information contained in the 2020 Husky Reserves Report is only an estimate and the actual production from, and ultimate reserves of, those properties may be greater or less than the estimates contained in such report.

Inclusion of Historical Information relating to Husky

The Arrangement was effected on January 1, 2021, and the integration of Cenovus’s and Husky’s business is ongoing. Cenovus has not yet completed independently evaluating and updating certain information relating to the assets, reserves and businesses acquired in the Arrangement and certain information contained in this MD&A and Cenovus’s public disclosure record is based on historical information relating to Husky. Such historical information relating to Husky is derived from, among other things, previous Husky public disclosure and from information provided by current and former Husky directors, officers and employees. Much of the disclosure relating to Husky relates to periods prior to Cenovus’s ownership of Husky, and therefore was generated by disclosure controls and procedures that may differ from those in place at Cenovus. Thus, information from the two companies may not have been generated and reported using equivalent standards. Further, Cenovus’s Management’s expectations about the combined entity’s future performance reflect the current state of its information about Husky and its operations and there can be no assurance that such information is accurate in all material respects. Inaccuracies in historical information relating to Husky may cause Cenovus’s financial and operational results to vary from our expectations, which may in turn adversely affect our financial condition, results of operations and share price.

Uncertainty related to Customers, Suppliers or Other Third Parties

As a result of the Arrangement, Cenovus may experience impacts on relationships with customers, suppliers or other third parties that may harm Cenovus’s business and results of operations. Certain customers, suppliers or other third parties may seek to terminate or modify contractual obligations whether or not such contractual rights are triggered as a result of the Arrangement. There can be no guarantee that customers, suppliers or other third parties will remain with or continue to have a relationship with Cenovus or Husky or do so on the same or similar contractual terms. If any customers, suppliers or other third parties seek to terminate or modify contractual

 

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obligations or discontinue their relationships with Cenovus or Husky, then Cenovus’s business and results of operations may be adversely affected.

Any disruptions with third parties could limit our ability to achieve the anticipated benefits of the Arrangement or may be detrimental to Cenovus’s and Husky’s existing businesses, operations and financial conditions.

Risks Associated with the Cenovus Warrants

There can be no assurance that an active public market for the Cenovus Warrants will be sustained. If such a market is sustained, the market price of the Cenovus Warrants may be adversely affected by a variety of factors relating to Cenovus’s business, including, without limitation, fluctuations in Cenovus’s operating and financial results, the results of any public announcements made by Cenovus and Cenovus’s failure to meet analysts’ expectations. In addition, the market price of the Cenovus common shares will significantly affect the market price of the Cenovus Warrants. This may result in significant volatility in the market price of the Cenovus Warrants and may negatively impact the value of the Cenovus Warrants.

Holders of Cenovus Warrants will experience dilution if the combined company issues additional Cenovus common shares in future offerings or under outstanding Cenovus Replacement Options and Cenovus Warrants. Such dilution may adversely affect the market price of the Cenovus common shares and may negatively impact the value of Cenovus shareholders’ investments.

Risks Related to Significant Shareholders of Cenovus

As of January 1, 2021, Hutchison Whampoa Europe Investments S.à r.l. (“Hutchison”), L.F. Investments S.à r.l (“L.F. Investments”), and ConocoPhillips own 15.7 percent, 11.5 percent and 10.3 percent of the common shares of Cenovus, respectively. Although each of Hutchison and L.F. Investments are subject to restrictions from selling or transferring Cenovus common shares through July 1, 2022 pursuant to the terms of their respective standstill agreement with Cenovus, the sale of Cenovus common shares held by any of Hutchison, L.F. Investments or ConocoPhillips into the market, either through open market trades on the Toronto and New York stock exchanges, through privately arranged block trades, or pursuant to prospectus offerings made in accordance with the respective registration rights agreement that each of Hutchison, L.F. Investments and ConocoPhillips have entered into with Cenovus, or market perception regarding ConocoPhillips’ intention to sell Cenovus common shares, could adversely affect market prices for Cenovus common shares.

While Hutchison and L.F. Investments are each subject to certain voting covenants pursuant to the terms of a standstill agreement they each entered into with Cenovus in connection with the Arrangement, each of Hutchison and L.F. Investments may be able to impact certain matters requiring shareholder approval.

Amount of Contingent Payments Payable to ConocoPhillips

In connection with the Conoco Acquisition, we agreed to make contingent payments under certain circumstances. The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the five year period following the closing of the Conoco Acquisition (May 17, 2017), and such payments may be significant. In addition, in the event that such further payments are made, this could have an adverse impact on our reported results and other metrics.

Tax Laws

Income tax laws, other laws or government incentive programs may in the future be changed or interpreted in a manner that adversely affects Cenovus, its financial results and its shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s detriment or the detriment of its shareholders. In addition, all of our tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders.

U.S. Tax Risk

In January 2021, a new U.S. presidential administration took office. The new administration campaigned on a platform that included several tax provisions that could potentially be detrimental to Cenovus. Those provisions included an increase in the U.S. federal corporate tax rate and a new corporate minimum tax. While the ability of the new administration to enact tax laws is uncertain, it is possible that Cenovus’s U.S. operations will be subject to increased levels of U.S. federal taxation in the future.

A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business, prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com.

 

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CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

 

Management is required to make estimates and assumptions and use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements.

Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements.

Joint Arrangements

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company considered the following:

 

·  

The intention of the joint arrangement was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life.

·  

The partnership agreements require the partners (Cenovus and Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of WRB is dependent on funding from the partners by way of partnership notes payable and loans.

·  

The WRB working interest relationship is operated whereby the operating partner takes product on behalf of the participants and is modified to account for the operating environment of the refining business.

·  

Phillips 66, as the operator, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnership from undertaking these roles themselves. In addition, the partnership does not have employees and, as such, are not capable of performing these roles.

·  

In the arrangement, output is taken by the partners, indicating that the partners have the rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangement.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have reached a stage where technical feasibility and commercial viability cannot be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Identification of CGUs

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail terminal, railcars, storage tanks, and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals.

Determining the Lease Term

In determining the lease term, Management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed if a significant event or a significant change in circumstances occurs which affects this assessment.

 

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Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of COVID-19. The outbreak and subsequent measures intended to limit the pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil.

The full extent of the impact of COVID-19 on the Company’s operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by Management in the preparation of its financial results.

The outbreak and current market conditions have increased the complexity of estimates and assumptions used to prepare the annual Consolidated Financial Statements, particularly related to recoverable amounts.

In addition, the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could result in a change in assumptions used in determining the recoverable amount and could affect the carrying value of the related assets. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain.

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test fair value less costs to sell and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands and Conventional segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Recoverable amounts for the Company’s refining assets, crude-by-rail terminal and related ROU assets use assumptions such as throughput, forward commodity prices, market crack spreads, operating expenses, transportation capacity, future capital expenditures, supply and demand conditions and the terminal values used. Recoverable amounts for the Company’s real estate ROU assets use assumptions such as real estate market conditions which includes market vacancy rates and sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

2020 Upstream Impairments

The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. All reserves have been evaluated as at December 31, 2020 by the IQREs.

 

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Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

 

      2021      2022      2023      2024      2025     

Average

Annual

Increase

Thereafter

(percent)

  

WTI (US$/barrel)

      47.17        50.17        53.17        54.97        56.07        2.0 % 

WCS (C$/barrel)

      44.63        48.18        52.10        54.10        55.19        2.0 % 

Edmonton C5+ (C$/barrel)

              59.24                63.19                67.34                69.77                71.18        2.0 % 

AECO (1) (C$/Mcf)

      2.88        2.80        2.71        2.75        2.80        2.0 % 

 

(1)

Assumes gas heating value of one million British thermal units per thousand cubic feet.

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at approximately two percent.

2020 Refining Impairments

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, operating costs, the terminal values and the discount rate. Forward crack spreads were based on quoted near-month contracts for WTI and spot prices for gasoline and diesel.

Crude Oil and Forward Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were:

 

  ·  

WTI forward prices used for 2021 to 2022 ranged from US$36.36 per barrel to US$50.84 per barrel and 2023 to 2025 ranged from US$49.66 per barrel to US$58.74 per barrel.

  ·  

WTI to West Texas Sour differential used for 2021 to 2022 ranged from US$0.37 per barrel to US$1.73 per barrel and 2023 to 2025 ranged from US$1.21 per barrel to US$1.81 per barrel.

  ·  

Group 3 forward market crack spread used for 2021 to 2022 ranged from US$11.56 per barrel to US$13.23 per barrel and 2023 to 2025 ranged from US$11.79 per barrel to US$16.58 per barrel.

  ·  

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets.

 

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Income Tax Provisions

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.

Changes in Accounting Policies

There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2020.

New Accounting Standards and Interpretations not yet Adopted

There are new standards, amendments to accounting standards and interpretations that are effective for annual periods beginning or after January 1, 2021 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2020. These standards and interpretations are not expected to have a material impact on our Consolidated Financial Statements. The standard applicable to us is as follows and will be adopted on its respective effective date:

Interest Rate Benchmark Reform

On August 27, 2020, the IASB published Interest Rate Benchmark Reform – Phase 2 (Amendments to IFRS 9, “Financial Instruments”, IAS 39, “Financial Instruments: Recognition and Measurement”, IFRS 7, “Financial Instruments: Disclosures”, IFRS 4, “Insurance Contracts” and IFRS 16) (“IBOR Phase 2 Amendments”), which provides clarity on the changes after the reform of an interest rate benchmark. The amendments are effective for annual periods beginning on or after January 1, 2021, with early application permitted. The IBOR Phase 2 Amendments primarily relate to the modification of financial instruments, allowing for a practical expedient for modifications required by the reform. The practical expedient for modifications is accounted for by updating the effective interest rate without modification of the financial instrument and is subject to satisfying all qualifying criteria. We expect the IBOR Phase 2 Amendments will not have a significant impact on our Consolidated Financial Statements.

CONTROL ENVIRONMENT

 

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of ICFR and disclosure controls and procedures (“DC&P”) as at December 31, 2020. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2020.

The effectiveness of our ICFR was audited as at December 31, 2020 by PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2020.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

SUSTAINABILITY

 

At Cenovus, sustainability is essential to the way we do business. It means creating a safe and inclusive workplace, partnering with local and Indigenous communities, and innovating to minimize our impact on the environment. We believe striking the right balance among environmental, economic and social considerations creates long-term value.

 

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To support our sustainability performance, our Sustainability Policy guides our activities in the areas of: Leadership and Governance, People, Environment, Stakeholder Engagement, Indigenous Engagement, and Community Involvement and Investment.

Cenovus is committed to world-class safety performance and ESG leadership. This includes ambitious ESG targets, robust management systems and transparent performance reporting. The Company will continue working to earn its position as a global energy supplier of choice by advancing clean technology and reducing emissions intensity. This includes the ambition of achieving net zero emissions by 2050. Cenovus will also continue building upon its strong local community relationships, with a focus on Indigenous economic reconciliation.

The targets Cenovus released in 2020 for its key ESG focus areas are the product of robust processes to ensure alignment with the Company’s business plan and strategy. Cenovus remains committed to pursuing ESG targets now that it has completed the Arrangement with Husky and will undertake a similarly thorough analysis before setting meaningful targets for the new portfolio. Once that work is complete in 2021 and approved by the Board, the new targets and plans to achieve them will be disclosed.

We published our 2019 ESG report in July 2020 to report on our management efforts and performance across the areas within our Sustainability Policy that are important to our stakeholders. Our ESG report is available on our website at cenovus.com.

OUTLOOK

 

We expect 2021 to be a challenging time for our industry and the global economy in general due to the impacts of COVID-19. With the continued uncertainty around COVID-19 and the scale of resurgence of COVID-19 cases, we anticipate crude oil and refined products demand to be volatile in 2021 with recovery dependent on the success of economic relaunches. We anticipate that an increase in demand for refined products will be an early indicator of recovery. Our top priority will be to maintain the strength of our balance sheet. We have ample liquidity, top-tier assets which we are able to effectively manage to respond to price signals, one of the lowest cost structures in the industry and have demonstrated our ability to reduce discretionary capital, all of which should allow us to continue to adapt to these challenges.

We continue to monitor the overall market dynamics to assess how we manage our Upstream production levels. Our assets can respond to market signals and ramp up production accordingly. Our decisions around production levels and refinery crude run rates will be focused on maximizing the value we receive for our products. We expect our 2021 annual Upstream production to average between 730,000 BOE per day and 780,000 BOE per day and total Downstream throughput of 500,000 barrels per day to 550,000 barrels per day.

With the close of the Arrangement, we estimated approximately $600 million in annual corporate and operating synergies and approximately $600 million in capital allocation synergies to be achievable. The 2021 budget positions us to achieve about $400 million of the estimated annual corporate and operating synergies and all of the estimated capital allocation synergies this year. Over the longer-term, we anticipate additional cost savings and margin enhancements based on further physical integration of upstream assets with downstream assets, which is expected to shorten the value chain and reduce condensate costs associated with heavy oil transportation. We continue to look for additional opportunities to reduce operating, capital, and G&A spending and increase our margins through strong operating performance and cost leadership while focusing on safe and reliable operations.

Given the challenges faced by our industry and the global economy and the closing of the Arrangement with Husky, achieving cumulative free funds flow of approximately $11 billion through 2024, as disclosed in our news release dated October 2, 2019, is under evaluation. We expect to develop a new five-year business plan for the Company later this year.

The following outlook commentary is focused on the next twelve months.

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

 

·  

We expect the general outlook for light crude oil prices will be tied primarily to the supply and demand response to the current uncertain price environment, the impact of oversupply, and global demand impacts amid COVID-19 concerns;

·  

Crude oil and refined product price volatility is expected to continue due to crude demand destruction as a result of COVID-19;

·  

The effectiveness and successful distribution of vaccines will be key to the pace of oil demand recovery;

·  

The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts;

·  

We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply cuts are sustained, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the Trans Mountain Expansion project, and the level of crude-by-rail activity; and

·  

We expect refining market crack spreads in 2021 to remain weak relative to normal as a result of significantly reduced refined products demand due to COVID-19, particularly in the first half of the year. Refining market

 

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crack spreads are expected to continue to fluctuate, adjusting for seasonal trends and refining run cuts in North America.

Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel, solvent and blending requirements at our Oil Sands operations.

 

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Natural gas prices have been challenged due to weaker demand as a result of COVID-19, but the forward curve is showing that the market expects AECO prices to rebound into 2021. Production declines from both associated gas and dry gas, along with rebounding U.S. demand and liquified natural gas exports, should tighten North American gas fundamentals in 2021 and result in stronger prices than 2020 on an annual basis.

We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, and emerging macro-economic factors. The Bank of Canada lowered its benchmark lending rate twice in 2020 to address the impacts of COVID-19 and is expected to continue to hold the interest rate until 2023.

 

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Our upstream crude oil production and most of our downstream refined products are exposed to movements in the WTI crude oil price. With the closing of the Arrangement, our exposure has gro wn on both the upstream and downstream sides of our business.

Our refining capacity is now focused in the U.S. Midwest along with smaller exposures to the USGC and Alberta. Cenovus is exposed to the crack spread in all of these markets.

Our exposure to crude differentials includes light-heavy and light-medium price differentials. Light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have refining capacity, and to a lesser degree in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differential, which is subject to transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product prices and differentials through the following:

 

·  

Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets;

·  

Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture value from both the WTI-WCS differential for Canadian crude oil as well as from spreads on refined products;

·  

Marketing agreements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners;

·  

Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production rates

 

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in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil price differentials;

·  

Traditional crude oil storage tanks in various geographic locations; and

·  

Financial hedge transactions – limiting the impact of fluctuations in crude oil and refined product prices by entering into financial transactions related to our exposures.

Key Priorities For 2021

We recently developed and shared updated guidance on January 28, 2021. In the current commodity price environment, we continue to focus on maintaining balance sheet strength and liquidity. Enhancing our financial resilience and flexibility while continuing to deliver safe and reliable operations will continue to be a top priority during these uncertain times.

Our corporate strategy focuses on maximizing shareholder value through cost leadership and realizing the best margins for our products. We expect to remain focused on disciplined capital investment allocation among the full suite of assets for the Company, and continued cost leadership to achieve margin improvement and environmental benefits.

Safe and Reliable Operations

Safe and reliable operations are our number one priority. Safety continues to be a core value that informs all of the decisions we make. We will continue to promote a safety culture in all aspects of our work and use a variety of programs to keep safety top of mind at all times.

Capture Synergies and Maintain Cost Leadership

The combination with Husky will further improve cost structure. The 2021 budget positions us to achieve about $400 million of annual corporate and operating synergies and an estimated $600 million in capital allocation synergies in 2021.

The annual corporate and operating cost synergies is well underway and is expected through the consolidation of information technology systems, eliminating other service overlaps, and through reductions to combined workforce and corporate overhead costs. Immediate efficiencies are also expected by implementing best practices from each company, including applying Cenovus’s operating expertise to Husky’s oil sands assets, leveraging the increased portfolio’s scale, and pursuing commercial and contract-related efficiencies on transportation, storage, and logistics marketing and blending opportunities.

Over the longer term, we anticipate additional cost savings and margin enhancements based on further physical integration. The integration of Cenovus’s upstream assets with Husky’s downstream and transportation, storage, and logistics portfolio is expected to shorten the value chain and reduce condensate costs associated with heavy oil transportation over the longer term.

We continue to achieve improvements in our operating and G&A costs. In 2021, we will continue to look for ways to improve efficiencies across Cenovus to drive incremental capital, operating and G&A cost reductions.

Disciplined Capital Investment

We released our 2021 guidance on January 28, 2021 for the Company and anticipate our total capital expenditures to be between $2.3 billion and $2.7 billion, including sustaining capital of approximately $2.1 billion and costs of $520 million to $570 million (excluding insurance proceeds) for the Superior Refinery rebuild. We will continue to be disciplined with our capital. The 2021 guidance is available on our website at cenovus.com.

Oil Sands capital investment for 2021, including Christina Lake, Foster Creek, Sunrise and Tucker oil sands projects, as well as the Lloydminster thermal projects and Cold and Enhanced Oil Recovery, is forecast to be between $850 million and $950 million. Oil Sands capital is primarily for sustaining production focused at Christina Lake, Foster Creek and the Lloydminster thermal assets. Our Oil Sands production is expected to range between 524,000 and 586,000 barrels per day for 2021.

Our Conventional segment capital investment is forecasted to be between $170 million and $210 million. This includes economic development in various plays to generate strong returns, improve underlying cost structures through volume enhancement and offset declines. Production is expected to range between 132,000 and 151,000 BOE per day for 2021.

Our Offshore segment, including operations and exploration prospects in the Asia Pacific region and Atlantic Canada region, capital investment is expected to be between $200 million and $250 million. This capital spend includes planned wells in China and continued development of the fields in the MDA-MBH and MDK fields in the Madura Strait, as well as baseline preservation capital for the West White Rose Project, which has been deferred for 2021 while we continue to evaluate options. Working Interest production from our Offshore segment is expected to range between 61,000 and 72,000 barrels per day.

In 2021, the Downstream segment, composed of Canadian and U.S. Manufacturing and Retail, we expect to invest between $1.0 billion and $1.2 billion and will continue to focus on refining reliability and maintenance, safety projects and high-return optimization opportunities as well as between $520 million and $570 million for the Superior rebuild project. The rebuild project will further improve our integration while reducing the Company’s

 

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exposure to WTI-WCS location differentials. Downstream throughput is expected to be in the range of 500,000 barrels per day to 550,000 barrels per day.

We expect to invest between $75 million and $100 million of corporate capital in 2021 across the Company.

In 2021, we plan to achieve capital allocation synergies across the Company by optimizing sustaining capital to the highest quality assets while maintaining safe and reliable operations across our portfolio.

As at December 31, 2020, our Net Debt position was $7.2 billion. The estimated incremental annual free funds flow from identified near-term synergies with the closing of the Arrangement is expected to accelerate balance sheet deleveraging. Through a combination of cash on hand and available capacity on our committed credit facilities and demand facilities, we have approximately $10.4 billion of liquidity under the combined company. In addition, WRB has available capacity of approximately $70 million, for Cenovus’s proportionate share, on its demand facilities. We will continue to focus on allocating free funds flow to reduce Net Debt to less than $10 billion and target a longer-term Net Debt level at or below $8 billion.

Maintaining Financial Resilience

We have top-tier assets, one of the lowest cost structures in our industry and a strong balance sheet, all of which position us to withstand the challenges of the current market environment. Our capital planning process is flexible, and spending can be reduced in response to commodity prices and other economic factors so we can maintain our financial resilience. The Arrangement removes a significant amount of exposure to WTI-WCS location differentials and reduces commodity price volatility. Our financial framework and flexible business plan allow multiple options to manage our balance sheet. We will continue to assess our spending plans on a regular basis while closely monitoring crude oil prices in 2021.

The Company’s priority will be to maximize free funds flow by focusing investments on sustaining capital expenditures which will position us to direct available free funds flow to the balance sheet and allow us to achieve a Net Debt target of $10 billion which approximates a Net Debt to Adjusted EBITDA target of less than 2.0 times, without the need for asset dispositions.

The low funds flow volatility, breakeven prices and corporate sustaining costs supports an investment grade profile and lower cost of capital through the commodity price cycle. We remain committed to maintaining our investment grade credit ratings.

Shareholder Returns

After achieving our balance sheet objectives, the Company’s free funds profile is expected to enable sustainable growth in shareholder distributions. The Board declared a first quarter dividend of $0.0175 per common share, payable on March 31, 2021, to common shareholder of record as of March 15, 2021. The Board declared a first quarter dividend on the Series 1, 2, 3, 5, and 7 preferred shares, payable on March 31, 2021, in the amount of

$8 million.

ESG

We are committed to ESG leadership. This includes ambitious ESG targets, robust management systems and transparent performance reporting. The Company will continue working to earn its position as a global energy supplier of choice by advancing clean technology and reducing emissions intensity. This includes the ambition of achieving net zero emissions by 2050. We will also continue building upon our strong local community relationships, with a focus on Indigenous economic reconciliation.

The targets Cenovus released in 2020 for its key ESG focus areas are the product of robust processes to ensure alignment with the company’s business plan and strategy. We remain committed to pursuing ESG targets now that we have completed the Arrangement with Husky and will undertake a similarly thorough analysis before setting meaningful targets for the new portfolio. Once that work is complete in 2021 and approved by the Board, the new targets and plans to achieve them will be disclosed.

 

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CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEAR ENDED DECEMBER 31, 2020

 

 

78   1.    DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
81   2.    BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
81   3.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
90   4.    CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
92   5.   

GENERAL AND ADMINISTRATIVE

92   6.    FINANCE COSTS
92   7.    FOREIGN EXCHANGE (GAIN) LOSS, NET
92   8.    DIVESTITURES
93   9.    OTHER (INCOME) LOSS, NET
93   10.    IMPAIRMENT CHARGES AND REVERSALS
96   11.    DISCONTINUED OPERATIONS
96   12.    INCOME TAXES
98   13.    PER SHARE AMOUNTS
98   14.    CASH AND CASH EQUIVALENTS
99   15.    ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
99   16.    INVENTORIES
99   17.    EXPLORATION AND EVALUATION ASSETS
100   18.    PROPERTY, PLANT AND EQUIPMENT, NET
101   19.    RIGHT-OF-USE ASSETS, NET
102   20.    OTHER ASSETS
102   21.    GOODWILL
102   22.    ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
102   23.    SHORT-TERM BORROWINGS
103   24.    LONG-TERM DEBT AND CAPITAL STRUCTURE
105   25.    LEASE LIABILITIES
105   26.    CONTINGENT PAYMENT
106   27.    DECOMMISSIONING LIABILITIES
106   28.    OTHER LIABILITIES
107   29.    PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
109   30.    SHARE CAPITAL
110   31.    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
110   32.    STOCK-BASED COMPENSATION PLANS
113   33.    EMPLOYEE SALARIES AND BENEFIT EXPENSES
113   34.    RELATED PARTY TRANSACTIONS
113   35.    FINANCIAL INSTRUMENTS
116   36.    RISK MANAGEMENT
119   37.    SUPPLEMENTARY CASH FLOW INFORMATION
120   38.    COMMITMENTS AND CONTINGENCIES
121   39.    SUBSEQUENT EVENT
 

 

 

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REPORT OF MANAGEMENT

Management’s Responsibility for the Consolidated Financial Statements

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Management’s best judgments.

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of five independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee met with Management and the independent auditors on at least a quarterly basis to review the interim Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors prior to their public release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors.

Management’s Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2020. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2020.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2020, as stated in their Report of Independent Registered Public Accounting Firm dated February 8, 2021. PricewaterhouseCoopers LLP has provided such opinions.

 

 

/s/ Alexander J. Pourbaix    /s/ Jeffrey R. Hart
Alexander J. Pourbaix    Jeffrey R. Hart
President &    Executive Vice-President &
Chief Executive Officer    Chief Financial Officer
Cenovus Energy Inc.    Cenovus Energy Inc.
February 8, 2021   

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Cenovus Energy Inc.

Opinions on the Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. and its subsidiaries (together, the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of earnings (loss), comprehensive income (loss), shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Change in Accounting Principle

As discussed in Note 3 to the Consolidated Financial Statements, the Company changed the manner in which it accounts for leases as of January 1, 2019 due to the adoption of IFRS 16, Leases.

Basis for Opinions

The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by Management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

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Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the Consolidated Financial Statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the Consolidated Financial Statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the Consolidated Financial Statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impact of Reserves and Resource Estimates on the Recoverable Amounts of Property, Plant and Equipment (“PP&E”) and any Allocated Goodwill (the “recoverable amounts”) of the Oil Sands and Conventional Cash Generating Units (“CGUs”) and on Depreciation, Depletion and Amortization (“DD&A”) Expense for the Oil Sands and Conventional Segments

As described in Notes 1, 3, 4, 10, 18 and 21 to the Consolidated Financial Statements, Management assesses its CGUs for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated DD&A and net impairment losses, may exceed its recoverable amount. Goodwill is tested for impairment at least annually. Management calculates depletion on the costs accumulated within each area using the unit-of-production method based on estimated proved reserves. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves. As at December 31, 2020, the Company had $19,748 million and $1,758 million in Oil Sands and Conventional PP&E assets net of accumulated DD&A and net impairment losses, respectively. Goodwill related to the Oil Sands segment amounted to $2,272 million as at December 31, 2020. In aggregate, the Company recognized $2,564 million of DD&A expense for the Oil Sands and Conventional segments, which included impairment of $555 million for the Conventional CGUs, for the year ended December 31, 2020. Management determined the recoverable amounts of the Oil Sands and Conventional CGUs based on their fair value less costs of disposal using discounted after-tax cash flows from reserves and resources. These fair value assessments required the use of significant estimates and judgments by Management related to forward commodity prices, expected production volumes, quantity of reserves and resources, royalty payments, and future development and operating expenses as well as estimates over discount rates. Management’s estimates of reserves and resources, as applicable, used for both the determination of the recoverable amounts of the Oil Sands and Conventional CGUs and the calculation of DD&A expense for the Oil Sands and Conventional segments have been developed by Management’s specialists, specifically independent qualified reserve evaluators.

The principal considerations for our determination that performing procedures relating to the impact of reserves and resource estimates on the recoverable amounts of the Oil Sands and Conventional CGUs and on DD&A expense for the Oil Sands and Conventional segments is a critical audit matter are (i) the significant amount of judgment required by Management, including the use of Management’s specialists, when developing the estimates of reserves and resources and the recoverable amounts; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in developing these estimates including forward commodity prices, expected production volumes, quantity of reserves and resources, future development and operating expenses, as well as discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

 

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Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimates of reserves and resources, the determination of the recoverable amounts of the Oil Sands and Conventional CGUs and the calculation of DD&A expense for the Oil Sands and Conventional segments. These procedures also included, among others, testing Management’s process for determining the recoverable amounts of the Oil Sands and Conventional CGUs and DD&A expense for the Oil Sands and Conventional segments, which included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in Management’s model; (iii) assessing the reasonability of the assumptions used by Management, including forward commodity prices, expected production volumes, quantity of reserves and resources, as well as future development and operating expenses; and (iv) testing the unit-of-production rates used to calculate DD&A expense. The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the quantity of reserves and resources used to determine the recoverable amounts of the Oil Sands and Conventional CGUs and DD&A expense for the Oil Sands and Conventional segments, as applicable. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings. Evaluating the assumptions used by Management’s specialists also involved assessing whether the assumptions used were reasonable considering the current and past performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were also used to assist in evaluating the reasonableness of the recoverability calculations, including the discount rate used within the models.

Impairment Assessment of PP&E for the Wood River and Borger CGUs within the Refining and Marketing Segment

As described in Notes 1, 3, 4, 10 and 18 to the Consolidated Financial Statements, Management assesses its CGUs for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated DD&A and net impairment losses, may exceed its recoverable amount. As at December 31, 2020, the Company had $3,476 million of PP&E assets net of accumulated DD&A and net impairment losses relating to refining equipment. For the year ended December 31, 2020, the carrying amount of the Borger CGU was determined to be greater than the recoverable amount and an impairment charge of $450 million was recorded as additional DD&A in the Refining and Marketing segment. No impairment of the Wood River CGU was identified by Management. Management determined the recoverable amounts of PP&E for the Wood River and Borger CGUs based on their fair value less costs of disposal using discounted after-tax cash flows requiring the use of significant estimates and judgments by Management related to forward crude oil prices, forward crack spreads, future capital expenditures, operating expenses, terminal values and the discount rates.

The principal considerations for our determination that performing procedures relating to the impairment assessment of PP&E for the Wood River and Borger CGUs within the Refining and Marketing segment is a critical audit matter are (i) the significant amount of judgment required by Management when developing the recoverable amounts of the Wood River and Borger CGUs; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in developing these estimates including forward crude oil prices, forward crack spreads, future capital expenditures, operating expenses and terminal values, as well as the discount rate applied; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

 

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Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s determination of the recoverable amounts of the Wood River and Borger CGU’s. These procedures also included, among others, testing Management’s process for determining the recoverable amounts of the Wood River and Borger CGU’s, which included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in these models; and (iii) assessing the reasonability of the assumptions used by Management, including forward crude oil prices, forward crack spreads, future capital expenditures and operating expenses. Evaluating the assumptions used by Management involved assessing whether the assumptions used were reasonable considering the current and past performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the recoverability calculations, including terminal values and the discount rates used within the models.

 

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta, Canada

February 8, 2021

We have served as the Company’s auditor since 2008.

 

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CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)

For the years ended December 31,

($ millions, except per share amounts)

 

                                                                                                                       
      Notes      2020        2019        2018    

Revenues

      1           

Gross Sales

         13,591          21,353          21,389    

Less: Royalties

         364          1,173          546    
              

 

 

     

 

 

  
        13,227          20,180          20,843    

Expenses

      1           

Purchased Product

         5,119          8,378          8,684    

Transportation and Blending

         4,444          5,184          5,942    

Operating

         1,930          2,088          2,184    

Inventory Write-Down (Reversal)

      16        555          49          60    

(Gain) Loss on Risk Management

      35        308          156          305    

Depreciation, Depletion and Amortization

      10,17,18,19            3,464          2,249          2,131    

Exploration Expense

      10,17        91          82          2,123    

General and Administrative

      5        292          331          1,020    

Finance Costs

      6        536          511          627    

Interest Income

         (9)         (12)         (19)   

Transaction Costs

      39        29          -          -    

Foreign Exchange (Gain) Loss, Net

      7        (181)         (404)         854    

Re-measurement of Contingent Payment

      26        (80)         164          50    

(Gain) Loss on Divestiture of Assets

      8        (81)         (2)         795    

Other (Income) Loss, Net

      9        40          9          13    
              

 

 

     

 

 

  

Earnings (Loss) From Continuing Operations Before Income Tax

         (3,230)         1,397          (3,926)   

Income Tax Expense (Recovery)

      12        (851)         (797)         (1,010)   
              

 

 

     

 

 

  

Net Earnings (Loss) From Continuing Operations

         (2,379)        2,194          (2,916)   

Net Earnings (Loss) From Discontinued Operations

      11        -          -          247    
              

 

 

     

 

 

  

Net Earnings (Loss)

         (2,379)        2,194          (2,669)   
              

 

 

     

 

 

  
              

 

 

     

 

 

  

Basic and Diluted Earnings (Loss) Per Share ($)

      13           

Continuing Operations

         (1.94)        1.78          (2.37)   

Discontinued Operations

         -          -          0.20    
              

 

 

     

 

 

  

Net Earnings (Loss) Per Share

         (1.94)        1.78          (2.17)   
              

 

 

     

 

 

  
              

 

 

     

 

 

  

 

 

See accompanying Notes to Consolidated Financial Statements.

 

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the years ended December 31,

($ millions)

 

                                                                                                                       
      Notes      2020     2019        2018    

Net Earnings (Loss)

         (2,379 )      2,194          (2,669)   

Other Comprehensive Income (Loss), Net of Tax

      31                 

Items That Will Not be Reclassified to Profit or Loss:

           

Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits

         (8)       5          (3)   

Change in the Fair Value of Equity Instruments at FVOCI (1)

        -         12          1    

Items That May be Reclassified to Profit or Loss:

           

Foreign Currency Translation Adjustment

         (44)       (228)         397    
             

 

 

     

 

 

  

Total Other Comprehensive Income (Loss), Net of Tax

         (52 )      (211)         395    
             

 

 

     

 

 

  

Comprehensive Income (Loss)

         (2,431 )      1,983         (2,274)   
             

 

 

     

 

 

  
             

 

 

     

 

 

  

 

 

(1)

Fair value through other comprehensive income (loss) (“FVOCI”).

See accompanying Notes to Consolidated Financial Statements.

 

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CONSOLIDATED BALANCE SHEETS

As at December 31,

($ millions)

 

                                                                          
      Notes      2020      2019  

Assets

         

Current Assets

         

Cash and Cash Equivalents

      14        378        186  

Accounts Receivable and Accrued Revenues

      15        1,488        1,556  

Income Tax Receivable

         21        10  

Inventories

      16        1,089        1,532  
              

 

 

  

Total Current Assets

         2,976        3,284  

Exploration and Evaluation Assets

      1,17        623        787  

Property, Plant and Equipment, Net

      1,18        25,411        27,834  

Right-of-Use Assets, Net

      1,19        1,139        1,325  

Other Assets

      20        313        211  

Deferred Income Taxes

      12        36        -    

Goodwill

      1,21        2,272        2,272  
              

 

 

  

Total Assets

         32,770        35,713  
              

 

 

  
              

 

 

  
        

Liabilities and Shareholders’ Equity

         

Current Liabilities

         

Accounts Payable and Accrued Liabilities

      22        2,018        2,229  

Short-Term Borrowings

      23        121        -    

Lease Liabilities

      25        184        196  

Contingent Payment

      26        36        79  

Income Tax Payable

         -          17  
              

 

 

  

Total Current Liabilities

         2,359        2,521  

Long-Term Debt

      24        7,441        6,699  

Lease Liabilities

      25        1,573        1,720  

Contingent Payment

      26        27        64  

Decommissioning Liabilities

      27        1,248        1,235  

Other Liabilities

      28        181        241  

Deferred Income Taxes

      12        3,234        4,032  
              

 

 

  

Total Liabilities

         16,063        16,512  

Shareholders’ Equity

         16,707        19,201  
              

 

 

  

Total Liabilities and Shareholders’ Equity

         32,770        35,713  
              

 

 

  
              

 

 

  

Commitments and Contingencies

      38        

 

 

See accompanying Notes to Consolidated Financial Statements.

Approved by the Board of Directors

 

/s/ Keith A. MacPhail    /s/ Claude Mongeau
Keith A. MacPhail    Claude Mongeau
Director    Director
Cenovus Energy Inc.    Cenovus Energy Inc.

 

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

($ millions)

 

      Share
Capital		           Paid in
Surplus		           Retained
Earnings		           AOCI (1)           Total  
     (Note 30)          (Note 30)                     (Note 31)             

As at December 31, 2017

      11,040          4,361          3,937          643          19,981  

Net Earnings (Loss)

      -           -           (2,669)          -           (2,669)  

Other Comprehensive Income (Loss)

      -           -           -           395          395  
                                                    

Total Comprehensive Income (Loss)

      -           -           (2,669)          395          (2,274)  

Stock-Based Compensation Expense

      -           6          -           -           6  

Dividends on Common Shares

      -           -           (245)          -           (245)  
                                                    

As at December 31, 2018

      11,040          4,367          1,023          1,038          17,468  

Net Earnings (Loss)

      -           -           2,194          -           2,194  

Other Comprehensive Income (Loss)

      -           -           -           (211)          (211)  
                                                    

Total Comprehensive Income (Loss)

      -           -           2,194          (211)          1,983  

Stock-Based Compensation Expense

      -           10          -           -           10  

Dividends on Common Shares

      -           -           (260)          -           (260)  
                                                    

As at December 31, 2019

      11,040          4,377          2,957          827          19,201  

Net Earnings (Loss)

      -           -           (2,379)          -           (2,379)  

Other Comprehensive Income (Loss)

      -           -           -           (52)          (52)  
                                                    

Total Comprehensive Income (Loss)

      -           -           (2,379)          (52)          (2,431)  

Stock-Based Compensation Expense

      -           14          -           -           14  

Dividends on Common Shares

      -           -           (77)          -           (77)  
                                                    

As at December 31, 2020

      11,040          4,391          501          775          16,707  
                                                    
                                                    

 

 

(1)

Accumulated other comprehensive income (loss) (“AOCI”).

See accompanying Notes to Consolidated Financial Statements.

 

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,

($ millions)

 

      Notes             2020             2019             2018  

Operating Activities

                  

Net Earnings (Loss)

           (2,379 )         2,194          (2,669 ) 

Depreciation, Depletion and Amortization

      10,17,18,19          3,464          2,249          2,131  

Exploration Expense

      10,17          91          82          2,123  

Inventory Write-Down (Reversal)

      16          555          49          60  

Deferred Income Tax Expense (Recovery)

      12          (838 )         (814 )         (794 ) 

Unrealized (Gain) Loss on Risk Management

      35          56          149          (1,249 ) 

Unrealized Foreign Exchange (Gain) Loss

      7          (131 )         (827 )         649  

Re-measurement of Contingent Payment

      26          (80 )         164          50  

(Gain) Loss on Discontinuance

      11          -           -           (301 ) 

(Gain) Loss on Divestiture of Assets

      8          (81 )         (2 )         795  

Unwinding of Discount on Decommissioning Liabilities

      27          57          58          63  

Realized Inventory Write-Down

           (572 )         (71 )         (13 ) 

Realized Foreign Exchange (Gain) Loss on Non-Operating Items

           (33 )         401          206  

Other

           38          70          670  

Net Change in Other Assets and Liabilities

           (72 )         (84 )         (72 ) 

Net Change in Non-Cash Working Capital

           198          (333 )         505  

Cash From (Used in) Operating Activities

           273          3,285          2,154  

Investing Activities

                  

Capital Expenditures – Exploration and Evaluation Assets

      17          (48 )         (73 )         (55 ) 

Capital Expenditures – Property, Plant and Equipment

      18          (811 )         (1,110 )         (1,322 ) 

Proceeds From Divestitures

      8,11          38          1          1,050  

Net Change in Investments and Other

           (4 )         (133 )         9  

Net Change in Non-Cash Working Capital

           (38 )         (117 )         (295 ) 

Cash From (Used in) Investing Activities

           (863 )         (1,432 )         (613 ) 
                 

Net Cash Provided (Used) Before Financing Activities

           (590 )         1,853          1,541  

Financing Activities

      37                 

Issuance (Repayment) of Short-Term Borrowings

           117          -           -   

Issuance of Long-Term Debt

           1,326          -           -   

Repayment of Long-Term Debt

           (112 )         (2,279 )         (1,144 ) 

Net Issuance (Repayment) of Revolving Long-Term Debt

           (220 )         276          (20 ) 

Principal Repayment of Leases

           (197 )         (150 )         -  

Dividends Paid on Common Shares

      13          (77 )         (260 )         (245 ) 

Other

           -           -           (1 ) 

Cash From (Used in) Financing Activities

           837          (2,413 )         (1,410 ) 

Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency

           (55 )         (35 )         40  

Increase (Decrease) in Cash and Cash Equivalents

           192          (595 )         171  

Cash and Cash Equivalents, Beginning of Year

           186          781          610  

Cash and Cash Equivalents, End of Year

           378          186          781  
                                   

 

 

See accompanying Notes to Consolidated Financial Statements.

 

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1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

 

Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with marketing activities and refining operations in the United States (“U.S.”).

Cenovus is incorporated under the “Canada Business Corporations Act” and its shares are listed on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 4100, 225 6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2.

On October 25, 2020, Cenovus announced that it had entered into a definitive agreement to combine with Husky Energy Inc. (“Husky”). The transaction was accomplished through a plan of arrangement (the “Arrangement”) pursuant to which Cenovus acquired all the issued and outstanding common shares of Husky in exchange for common shares and common share purchase warrants of Cenovus. In addition, all of the issued and outstanding Husky preferred shares were exchanged for Cenovus preferred shares with substantially identical terms. The Arrangement closed on January 1, 2021 (see Note 39).

The Arrangement will combine oil sands and heavy oil assets with extensive transportation, storage and logistics and downstream infrastructure, creating opportunities to optimize the margin captured across the heavy oil value chain. The combined company will be largely integrated reducing exposure to Alberta heavy oil price differentials while maintaining exposure to global commodity prices.

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating margin. The Company’s reportable segments at December 31, 2020 are:

 

  ·  

Oil Sands, which includes the development and production of bitumen in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development.

 

  ·  

Conventional, which includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas in Alberta and British Columbia and the exploration for heavy oil in Marten Hills area. The assets include interests in numerous natural gas processing facilities. The Company renamed its Deep Basin segment to Conventional in 2020 and its new resource play, Marten Hills, was reclassified from the Oil Sands segment to the Conventional segment. Comparative periods have been reclassified. On December 2, 2020, the Company completed the sale of its Marten Hills assets (see Note 8).

 

  ·  

Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S.

 

  ·  

Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides.

The following tabular financial information presents the segmented information first by segment, then by product and geographic location.

 

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A) Results of Operations – Segment and Operational Information             
     Oil Sands          Conventional          Refining and Marketing  

For the years ended December 31,

      2020            2019            2018            2020            2019            2018            2020            2019            2018  

Revenues

                                           

Gross Sales

      7,514          10,838          10,026          635          691          904          6,051          10,513          11,183  

Less: Royalties

      324          1,143          473          40          30          73          -          -          -  
     7,190          9,695          9,553          595          661          831          6,051          10,513          11,183  

Expenses

                                           

Purchased Product

      -          -          -          -          -          -          5,397          8,795          9,201  

Transportation and Blending

      4,399          5,152          5,879          81          82          90          -          -          -  

Operating

      1,094          1,039          1,037          318          337          403          824          948          927  

Inventory Write-Down (Reversal)

      316          -          -          -          -          -          239          49          60  

(Gain) Loss on Risk Management

      268          23          1,551          -          -          26          (21 )         (16 )         (1 ) 

Operating Margin

      1,113          3,481          1,086          196          242          312          (388 )         737          996  

Depreciation, Depletion and Amortization

      1,684          1,543          1,439          880          319          412          739          280          222  

Exploration Expense

      9          18          6          82          64          2,117          -          -          -  

Segment Income (Loss)

      (580 )         1,920          (359 )         (766 )         (141 )         (2,217 )         (1,127 )         457          774  
                                                                                                
                                     

Corporate and

Eliminations

          Consolidated  

For the years ended December 31,

                                             2020            2019            2018            2020            2019            2018  

Revenues

                                           

Gross Sales

                     (609 )         (689 )         (724 )         13,591          21,353          21,389  

Less: Royalties

                     -          -          -          364          1,173          546  
                    (609 )         (689 )         (724 )         13,227          20,180          20,843  

Expenses

                                           

Purchased Product

                     (278 )         (417 )         (517 )         5,119          8,378          8,684  

Transportation and Blending

                     (36 )         (50 )         (27 )         4,444          5,184          5,942  

Operating

                     (306 )         (236 )         (183 )         1,930          2,088          2,184  

Inventory Write-Down (Reversal)

                     -          -          -          555          49          60  

(Gain) Loss on Risk Management

                     61          149          (1,271 )         308          156          305  

Depreciation, Depletion and Amortization

      161          107          58          3,464          2,249          2,131  

Exploration Expense

                     -          -          -          91          82          2,123  

Segment Income (Loss)

                     (211 )         (242 )         1,216          (2,684 )         1,994          (586 ) 

General and Administrative

                     292          331          1,020          292          331          1,020  

Finance Costs

                     536          511          627          536          511          627  

Interest Income

                     (9 )         (12 )         (19 )         (9 )         (12 )         (19 ) 

Transaction Costs

                     29          -          -          29          -          -  

Foreign Exchange (Gain) Loss, Net

                     (181 )         (404 )         854          (181 )         (404 )         854  

Re-measurement of Contingent Payment

      (80 )         164          50          (80 )         164          50  

(Gain) Loss on Divestiture of Assets

                     (81 )         (2 )         795          (81 )         (2 )         795  

Other (Income) Loss, Net

                     40          9          13          40          9          13  
                                      546          597          3,340          546          597          3,340  

Earnings (Loss) From Continuing Operations Before Income Tax

           (3,230 )         1,397          (3,926 ) 

Income Tax Expense (Recovery)

                                    (851 )         (797 )         (1,010 ) 

Net Earnings (Loss) From Continuing Operations

                (2,379 )         2,194          (2,916 ) 
                                                            

 

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B) Revenues by Product

 

For the years ended December 31,

      2020            2019            2018  

Upstream

             

Crude Oil

      7,270          9,790          9,662  

NGLs

      142          202          333  

Natural Gas

      315          299          320  

Other

      58          65          69  

Refined Products

      4,734          8,291          9,032  

Market Optimization

      1,317          2,222          2,151  

Corporate and Eliminations

      (609 )         (689 )         (724 ) 

Revenues From Continuing Operations

          13,227              20,180          20,843  
                              
C) Geographical Information             
  

 

Revenues

 

For the years ended December 31,

      2020            2019            2018  

Canada

      8,399          11,798          11,694  

United States

      4,828          8,382          9,149  

Consolidated

      13,227          20,180          20,843  
                              
          Non-Current Assets (1)  

As at December 31,

                   2020            2019  

Canada

           26,168          28,336  

United States

           3,590          4,093  

Consolidated

           29,758              32,429  
                        

(1)    Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, other assets and goodwill.

Export Sales

Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers outside of Canada were $2,639 million (2019 – $4,002 million; 2018 – $2,500 million).

Major Customers

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2020, Cenovus had three customers (2019 – two; 2018 – three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $4,323 million, $1,834 million and $1,472 million, respectively (2019 – $6,922 million and $2,316 million; 2018 – $7,840 million, $2,285 million and $2,263 million), which are included in all of the Company’s operating segments.

D) Assets by Segment    

 

     E&E Assets (1)      PP&E             ROU Assets  

As at December 31,

      2020                 2019                 2020                 2019                 2020                 2019  

Oil Sands

          617             594           19,748           20,924           623           768  

Conventional

      6           193           1,758           2,433           3           3  

Refining and Marketing

      -           -           3,652           4,131           79           77  

Corporate and Eliminations

      -           -           253           346           434           477  

Consolidated

      623           787           25,411           27,834           1,139           1,325  
                                                                    
                                 Goodwill      Total Assets  

As at December 31,

                                          2020                 2019                 2020                 2019  

Oil Sands

                  2,272           2,272           24,656           26,203  

Conventional

                  -           -           1,953           2,754  

Refining and Marketing

                  -           -           4,951           5,688  

Corporate and Eliminations

                  -           -           1,210           1,068  

Consolidated

                      2,272               2,272               32,770               35,713  
                                                        

(1)     Prior to its sale, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment and the comparative period was reclassified.

 

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E) Capital Expenditures (1)

 

For the years ended December 31,

      2020                   2019                 2018  

Capital Investment (2)

              

Oil Sands

      427             656           870  

Conventional

      78             103           228  

Refining and Marketing

      276             280           208  

Corporate and Eliminations

      60             137           57  
     841               1,176             1,363  

Acquisition Capital

               

Oil Sands

      6             2           319  

Conventional

      12             7           22  

Refining and Marketing

      -             4           -  

Total Capital Expenditures

              859                     1,189                   1,704  
                                

 

(1)

Includes expenditures on PP&E and E&E assets.

(2)

Prior to its sale, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment and the comparative periods were reclassified.

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

 

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).

These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Company’s accounting policies disclosed in Note 3.

These Consolidated Financial Statements were approved by the Board of Directors on February 8, 2021.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

A) Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s refining activities are conducted through the joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets, liabilities, revenues and expenses.

An associate is an entity for which the Company has significant influence over but does not control or jointly control the investee. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter to recognize the Company’s share of the investee’s profit or loss and other comprehensive income (“OCI”).

B) Foreign Currency Translation

Functional and Presentation Currency

The Company’s functional and presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in OCI as cumulative translation adjustments.

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests.

 

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Transactions and Balances

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period-end date. Any gains or losses are recorded in the Consolidated Statements of Earnings (Loss).

C) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided.

Cenovus recognizes revenue from the following major products and services:

 

  ●  

Sale of crude oil, NGLs and natural gas.

  ●  

Sale of petroleum and refined products.

  ●  

Natural gas processing revenue.

  ●  

Marketing and transportation services.

  ●  

Fee-for-service hydrocarbon trans-loading services.

The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas and petroleum and refined products, which is generally at a point in time. Performance obligations for natural gas processing revenue, marketing, transportation services and trans-loading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period. Revenue associated with natural gas processing, marketing, transportation services and trans-loading services are based, generally on fixed price contracts.

Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with unfulfilled performance obligations.

D) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending, are recognized when the product is sold.

E) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.

Costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

F) Employee Benefit Plans

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component and an other post-employment benefit plan (“OPEB”).

Pension expense for the defined contribution pension is recorded as the benefits are earned.

The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans.

 

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Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:

 

  ●  

Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs.

  ●  

Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

  ●  

Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods.

Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded.

From time-to-time, the Company may provide certain other long-term incentive benefits to employees. In 2019, a one-time incentive program was introduced whereby a cash award equivalent to the employee’s base salary is payable if Cenovus achieves prior to February 12, 2024 a target share price of $20 per share for a period of 20 consecutive trading days on the TSX (the “Plan”). All employees, except for the President & Chief Executive Officer, are eligible and new employees are eligible for a pro-rated award based on start date provided they are employed on the payout date. The obligation related to this Plan is estimated as the probability of the payout being achieved multiplied by the expected payout amount. The obligation is recognized over the greater of (i) the time to earliest payout of February 13, 2022; and (ii) the estimated time until payout is achieved, prior to February 12, 2024 as general and administrative expense.

G) Government Grants

Government grants are recognized when there is reasonable assurance that the grant will be received and all conditions associated with the grant are met. Grants related to assets are recorded as a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the services have been performed.

H) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

I) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

 

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J) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less.

K) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

L) Exploration and Evaluation Assets

Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable internal costs. E&E assets are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired or the future economic value has decreased. E&E costs are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.

Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as depreciation, depletion and amortization (“DD&A”), is recognized on this production using a unit-of-production method based on estimated proved reserves determined using forward prices and costs and considering any estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an energy equivalent basis.

Non-producing assets classified as E&E are not depleted.

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

Any gains or losses from the divestiture of E&E assets are recognized in net earnings.

M) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated DD&A, and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

Any gains or losses from the divestiture of PP&E are recognized in net earnings.

Development and Production Assets

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Other Upstream Assets

Other upstream assets include information technology assets used to support the upstream business. These assets are depreciated on a straight-line basis over their useful lives of three years. Other upstream assets also include gross overriding royalty interests (“GORRs”) in certain oil and gas properties and are depleted using a unit-of-production method.

 

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Refining Assets

The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

 

●   Land improvements and buildings

    25 to 40 years

●   Office equipment and vehicles

    3 to 15 years

●   Refining equipment

    10 to 60 years

The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate.

Other Assets

Costs associated with the crude-by-rail terminal, infrastructure, office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three years to 60 years.

The residual value, the method of amortization and the useful lives of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

N) Impairment of Non-Financial Assets

PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”) and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.

O) Leases

The Company adopted IFRS 16, “Leases” (“IFRS 16”) on January 1, 2019 using the modified retrospective approach; therefore comparative periods were not restated.

Policy Applicable From January 1, 2019

Leases

The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company has elected not to separate non-lease components.

As Lessee

Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value

 

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basis. Lease liabilities include the net present value of fixed payments, costs to be incurred by the lessee in dismantling, removing and restoring the underlying asset, variable lease payments that are based on an index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating the lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with reasonably similar characteristics.

Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings over the lease term.

The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the Company will exercise a purchase, extension or termination option that is within the control of the Company.

When the lease liability is remeasured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero.

The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date.

The ROU asset is depreciated, on a straight-line basis, over the shorter of the estimated useful life of the asset or the lease term. The ROU asset may be adjusted for certain remeasurements of the lease liability and impairment losses.

Leases that have terms of less than twelve months or leases on which the underlying asset is of low value are recognized as an expense in the Consolidated Statements of Earnings (Loss) on a straight-line basis over the lease term.

A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will remeasure the lease liability using the Company’s incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope.

As Lessor

As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments received under operating leases as income on a straight-line basis over the lease term as other income.

When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the sublease is classified as an operating lease.

Policy Applicable Before January 1, 2019

Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease term.

Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased asset is depreciated over the shorter of the estimated useful life of the asset or the lease term.

P) Intangible Assets

Intangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the

 

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intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset.

Q) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited to net earnings.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

R) Provisions

General

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings (Loss).

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Onerous Contract Provisions

Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss).

S) Share Capital

Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any income taxes.

T) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), performance share units (“PSUs”), restricted share units (“RSUs”), and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expense, or E&E assets and PP&E when directly related to exploration or development activities.

 

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Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur.

U) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, net investment in finance leases, investments in the equity of private companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payment, risk management liabilities and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously.

The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

 

  ●  

Level 1 inputs are quoted prices in active markets for identical assets and liabilities.

  ●  

Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly.

  ●  

Level 3 inputs are unobservable inputs for the asset or liability.

Classification and Measurement of Financial Assets

The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets:

 

  ●  

Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

  ●  

FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

  ●  

Fair Value through Profit or Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets.

On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis.

At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.

Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model.

A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership.

Impairment of Financial Assets

The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured

 

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as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component.

Classification and Measurement of Financial Liabilities

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable.

Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.

A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows and a gain or loss is recorded in net earnings.

Derivatives

Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

Derivative financial instruments are measured at FVTPL unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

V) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2020.

W) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2021 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2020. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements. The standard applicable to Cenovus is as follows and will be adopted on its effective date:

Interest Rate Benchmark Reform

On August 27, 2020, the IASB published Interest Rate Benchmark Reform – Phase 2 (Amendments to IFRS 9, “Financial Instruments”, IAS 39, “Financial Instruments: Recognition and Measurement”, IFRS 7, “Financial Instruments: Disclosures”, IFRS 4, “Insurance Contracts” and IFRS 16) (“IBOR Phase 2 Amendments”), which provides clarity on the changes after the reform of an interest rate benchmark. The amendments are effective for annual periods beginning on or after January 1, 2021, with early application permitted. The IBOR Phase 2 Amendments primarily relate to the modification of financial instruments, allowing for a practical expedient for modifications required by the reform. The practical expedient for modifications is accounted for by updating the effective interest rate without modification of the financial instrument and is subject to satisfying all qualifying criteria. The Company expects the IBOR Phase 2 Amendments will not have a significant impact on the Consolidated Financial Statements.

 

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4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

 

The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

A) Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.

Joint Arrangements

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company considered the following:

 

  ●  

The intention of the joint arrangement was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life.

  ●  

The partnership agreements require the partners (Cenovus and Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of WRB is dependent on funding from the partners by way of partnership notes payable and loans.

  ●  

The WRB working interest relationship is operated whereby the operating partner takes product on behalf of the participants and is modified to account for the operating environment of the refining business.

  ●  

Phillips 66, as the operator, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnership from undertaking these roles themselves. In addition, the partnership does not have employees and, as such, are not capable of performing these roles.

  ●  

In the arrangement, output is taken by the partners, indicating that the partners have the rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangement.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals.

 

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Determining the Lease Term

In determining the lease term, Management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed if a significant event or a significant change in circumstances occurs which affects this assessment.

B) Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of the coronavirus (“COVID-19”). The outbreak and subsequent measures intended to limit the pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil.

The full extent of the impact of COVID-19 on the Company’s operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by Management in the preparation of its financial results.

The outbreak and current market conditions have increased the complexity of estimates and assumptions used to prepare the annual Consolidated Financial Statements, particularly related to recoverable amounts.

In addition, the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could result in a change in assumptions used in determining the recoverable amount and could affect the carrying value of the related assets. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain.

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands and Conventional segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Recoverable amounts for the Company’s refining assets, crude-by-rail terminal and related ROU assets use assumptions such as throughput, forward commodity prices, market crack spreads, operating expenses, transportation capacity, future capital expenditures, supply and demand conditions and the terminal values used. Recoverable amounts for the Company’s real estate ROU assets use assumptions such as real estate market conditions which includes market vacancy rates and sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

 

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Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward commodity prices, quantity of reserves and resources, production costs, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets.

Income Tax Provisions

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.

5. GENERAL AND ADMINISTRATIVE

 

 

For the years ended December 31,

        2020                  2019                  2018  

Salaries and Benefits

        145            143            205  

Administrative and Other

        84            95            177  

Onerous Contract Provisions (Recovery)

        18            (5 )           629  

Stock-Based Compensation Expense (Note 32)

        49            67            9  

Other Long-Term Incentive Expense (Recovery)

        (4 )           31            -  
       292              331              1,020  
                                    

 

6. FINANCE COSTS

 

 

For the years ended December 31,

        2020                  2019                  2018  

Interest Expense – Short-Term Borrowings and Long-Term Debt

        392            407            516  

Net (Discount) Premium on Redemption of Long-Term Debt (Note 24)

        (25 )           (63 )           17  

Interest Expense – Lease Liabilities (Note 25)

        87            82            -  

Unwinding of Discount on Decommissioning Liabilities (Note 27)

        57            58            62  

Other

        25            27            32  
       536              511              627  
                                    

 

7. FOREIGN EXCHANGE (GAIN) LOSS, NET

 

 

For the years ended December 31,

        2020                  2019                  2018  

Unrealized Foreign Exchange (Gain) Loss on Translation of:

                   

U.S. Dollar Debt Issued From Canada

        (194 )           (800 )           602  

Other

        63            (27 )           47  

Unrealized Foreign Exchange (Gain) Loss

        (131 )           (827 )           649  

Realized Foreign Exchange (Gain) Loss

        (50 )           423            205  
       (181)              (404)              854  
                                    

8. DIVESTITURES

 

On December 2, 2020, the Company sold its Marten Hills assets in northern Alberta to Headwater Exploration Inc. (“Headwater”) for total consideration of $138 million, excluding the retained GORR. A before-tax gain of $79 million was recorded on the sale (after-tax gain – $65 million). Total consideration received consists of $33 million in cash, 50 million common shares valued at $97 million and 15 million share purchase warrants valued at $8 million at the

 

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date of close. The share purchase warrants have a three-year term and an exercise price of $2.00 per share. The Company retained a GORR in the Marten Hills assets which was reclassified from E&E to PP&E for $41 million on the date of close. The investment in Headwater is held in other assets (see Note 20).

On September 6, 2018, the Company completed the sale of Cenovus Pipestone Partnership (“CPP”), a wholly-owned subsidiary, for cash proceeds of $625 million, before closing adjustments. CPP held the Company’s Pipestone and Wembley natural gas and liquids business in northwestern Alberta and included the Company’s 39 percent operated working interest in the Wembley gas plant. A before-tax loss of $797 million was recorded on the sale (after-tax – $557 million).

9. OTHER (INCOME) LOSS, NET

 

For the year ended December 31, 2020, the Company recorded a $100 million loss related to the Keystone XL pipeline project.

The Government of Canada passed the Canada Emergency Wage Subsidy (“CEWS”) as part of its COVID-19 Economic Response Plan. The program is effective from March 15, 2020 to June 2021. For the year ended December 31, 2020, the Company recorded $40 million in other income from the CEWS program.

For the year ended December 31, 2020, the Company recognized $24 million of lease income (2019 – $17 million). Lease income is earned on tank subleases, operating leases related to the Company’s real estate ROU assets in which Cenovus is the lessor, and from the recovery of non-lease components for operating costs and unreserved parking related to the Company’s net investment in finance leases. Finance leases are included in other assets as net investment in finance leases. The Company adopted IFRS 16 on January  1, 2019 using the modified retrospective approach; therefore, comparative periods were not restated.

10. IMPAIRMENT CHARGES AND REVERSALS

 

A) Cash-Generating Unit Net Impairments

On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

2020 Upstream Impairments

During the three months ended March 31, 2020, the Company tested its upstream CGUs and CGUs with associated goodwill for impairment. As a result, the Company recorded an impairment loss of $315 million as additional DD&A in the Conventional segment due to the decline in forward crude oil and natural gas prices. As at March 31, 2020, there was no impairment of goodwill or Oil Sands CGUs.

As at December 31, 2020, indicators of impairment were noted for the Company’s Conventional assets due to a change in future development plans since the Company last tested for impairment as at March 31, 2020. Therefore, the Company tested its Conventional CGUs for impairment and determined that the carrying amount was greater than the recoverable amount for certain CGUs and recorded an additional impairment loss of $240 million as DD&A.

For the purpose of impairment testing, goodwill is allocated to the CGU of which it relates. There was no impairment of goodwill as at December 31, 2020.

The following table summarizes the year ended December 31, 2020 impairment losses and estimated recoverable amounts as at December 31, 2020 by CGU:

 

CGU    Impairment
Amount		         Recoverable
Amount

Clearwater

    260      160

Elmworth-Wapiti

    120      259

Kaybob-Edson

    175        384

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. All reserves have been evaluated as at December 31, 2020 by the Company’s IQREs.

 

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Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

 

      2021      2022      2023      2024      2025      Average
Annual
Increase
Thereafter		  

WTI (US$/barrel) (1)

      47.17        50.17        53.17        54.97        56.07        2.0 % 

WCS (C$/barrel) (2)

      44.63        48.18        52.10        54.10        55.19        2.0 % 

Edmonton C5+ (C$/barrel)

      59.24        63.19        67.34        69.77        71.18        2.0 % 

AECO (C$/Mcf) (3)

      2.88        2.80        2.71        2.75        2.80        2.0 % 

 

(1)

West Texas Intermediate (“WTI”).

(2)

Western Canadian Select (“WCS”).

(3)

Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units per thousand cubic feet (“Mcf”).

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation was estimated at approximately two percent.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount in the impairment testing completed as at December 31, 2020 for the following CGUs:

 

     Increase (Decrease) to Recoverable Amount  
      One Percent
Increase in
the Discount
Rate		             One Percent
Decrease in
the Discount
Rate		             Five Percent
Increase in
the Forward
Price
Estimates		             Five Percent
Decrease in
the Forward
Price
Estimates		  

Clearwater

      (5 )         6          52          (97 ) 

Elmworth-Wapiti

      (7 )         8          54          (96 ) 

Kaybob-Edson

      (13 )               14                54                (106 ) 

2020 Refining Impairments

As at September 30, 2020, the recovery in demand for refined products from the impact of COVID-19 lagged expectations resulting in higher than anticipated inventory levels. These factors, along with low market crack spreads and crude oil processing runs for North American refineries, were identified as potential indicators of impairment for the Wood River and Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was determined to be greater than the recoverable amount and an impairment charge of $450 million was recorded as additional DD&A in the Refining and Marketing segment. The recoverable amount of the Borger CGU was estimated at $692 million, using a discounted cash flow method in accordance with IFRS. As at September 30, 2020, no impairment of the Wood River CGU was identified. As at December 31, 2020, there were no further indicators of impairment noted since the Company last tested as at September 30, 2020.

Key Assumptions

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, operating costs, terminal values and the discount rate. Forward crack spreads were based on quoted near-month contracts for WTI and spot prices for gasoline and diesel.

Crude Oil and Forward Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were:

 

  ·  

WTI forward prices used for 2021 to 2022 ranged from US$36.36 per barrel to US$50.84 per barrel and 2023 to 2025 ranged from US$49.66 per barrel to US$58.74 per barrel.

  ·  

WTI to West Texas Sour differential used for 2021 to 2022 ranged from US$0.37 per barrel to US$1.73 per barrel and 2023 to 2025 ranged from US$1.21 per barrel to US$1.81 per barrel.

  ·  

Group 3 forward market crack spread used for 2021 to 2022 ranged from US$11.56 per barrel to US$13.23 per barrel and 2023 to 2025 ranged from US$11.79 per barrel to US$16.58 per barrel.

  ·  

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.

 

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Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount in the impairment testing completed as at September 30, 2020 for the following CGU:

 

     Increase (Decrease) to Recoverable Amount  
      One Percent
Increase in
the Discount
Rate		             One Percent
Decrease in
the Discount
Rate		             Five Percent
Increase in
the Forward
Price
Estimates		             Five Percent
Decrease in
the Forward
Price
Estimates		  

Borger

      (71 )               81                263                (264 ) 

2020 ROU Asset Impairments

As at March 31, 2020, the temporary suspension of the Company’s crude-by-rail program was considered to be an indicator of impairment for the railcar CGU. As a result, the CGU was tested for impairment and an impairment expense of $3 million was recorded as additional DD&A in the Refining and Marketing segment.

2019 Upstream Impairments

As at December 31, 2019, the Company tested its Conventional CGUs for impairment as there were indicators of impairment due to a decline in forward natural gas prices. As at December 31, 2019, there were no impairments of goodwill or the Company’s CGUs.

2018 Net Upstream Impairments

As at December 31, 2018, the Company tested its upstream CGUs for impairment. As at December 31, 2018, there was no impairment of goodwill or the Company’s CGUs. However, the impairment test provided evidence that previously recognized impairment losses should be reversed.

As at December 31, 2018, the recoverable amount of the Clearwater CGU was estimated to be $761 million. Earlier in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline in forward prices. The impairment was recorded as additional DD&A in the Conventional segment (formerly Deep Basin). In the fourth quarter of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal was due to improved recovery, extensions and well performance and changes to the development plan.

B) Asset Impairments and Write-downs

Exploration and Evaluation Assets

For the year ended December 31, 2020, $9 million and $82 million of previously capitalized E&E costs were written off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be recoverable and recorded as exploration expense.

In 2019, $18 million and $64 million of previously capitalized E&E costs were written off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be recoverable and recorded as exploration expense.

In 2018, Management completed a comprehensive review of the Conventional development plan, formerly known as Deep Basin, considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. As such, previously capitalized E&E costs of $2.1 billion were written off as exploration expense in the Elmworth, Wapiti, Kaybob, Edson and Clearwater areas within the Conventional segment.

Property, Plant and Equipment, Net

For the year ended December 31, 2020, $48 million and $4 million of previously capitalized PP&E costs were written off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be recoverable. In addition, $52 million of previously capitalized PP&E costs relating to information technology assets were written off due to synergies identified as a result of the Arrangement. The impairment was recorded as additional DD&A in the Corporate and Eliminations segment.

 

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11. DISCONTINUED OPERATIONS

 

The results of operations from the former Conventional segment was reported as a discontinued operation.

For the year ended December 31, 2018, the Company recorded net earnings from discontinued operations of $247 million. The cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows were $36 million related to cash from operating activities and $404 million related to cash from investing activities.

On January 5, 2018, the Company completed the sale of its Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of $343 million was recorded on the sale.

12. INCOME TAXES

 

The provision for income taxes is:

 

For the years ended December 31,

        2020              2019              2018  

Current Tax

                   

Canada

        (14 )           14            (128 ) 

United States

        1            3            2  

Total Current Tax Expense (Recovery)

        (13 )           17            (126 ) 

Deferred Tax Expense (Recovery)

        (838 )           (814 )           (884 ) 

Tax Expense (Recovery) From Continuing Operations

        (851 )           (797 )           (1,010 ) 
                                    

For the year ended December 31, 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU, impairment in the Conventional segment and current period operating losses that will be carried forward, excluding unrealized foreign exchange gains and losses on long-term debt. In 2020, the Government of Alberta accelerated the reduction in the provincial corporate tax rate from 12 percent to eight percent.

 

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, the Company recorded a deferred income tax recovery of $671 million for the year ended December 31, 2019. In addition, the Company recorded a deferred income tax recovery of $387 million due to an internal restructuring of the Company’s U.S. operations resulting in a step-up in the tax basis of the Company’s refining assets.

 

In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down of the Conventional E&E assets and a $78 million recovery arising from an adjustment to the tax basis of the Company’s refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its interest in WRB, which due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. The maximum recovery related to the carry back of losses to recover tax paid was reached in 2018.

 

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

 

 

 

 

 

For the years ended December 31,

        2020              2019              2018  

Earnings (Loss) From Continuing Operations Before Income Tax

        (3,230 )           1,397            (3,926 ) 

Canadian Statutory Rate

        24.0%            26.5%            27.0%  

Expected Income Tax Expense (Recovery) From Continuing Operations

        (775 )           370            (1,060 ) 

Effect on Taxes Resulting From:

                   

Statutory and Other Rate Differences

        19            (52 )           (57 ) 

Non-Taxable Capital (Gains) Losses

        (42 )           (38 )           89  

Non-Recognition of Capital (Gains) Losses

        (42 )           (39 )           87  

Adjustments Arising From Prior Year Tax Filings

        (8 )           4            3  

Recognition of U.S. Tax Basis

        -            (387 )           (78 ) 

Alberta Corporate Rate Reduction

        (7 )           (671 )           -  

Other

        4            16            6  

Total Tax Expense (Recovery) From Continuing Operations

        (851 )           (797 )           (1,010 ) 

Effective Tax Rate

        26.3%            (57.1)%            25.7%  
                                    

 

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The analysis of deferred income tax liabilities and deferred income tax assets is as follows:

 

For the years ended December 31,

        2020                  2019  

Deferred Income Tax Liabilities

            

Deferred Income Tax Liabilities to be Settled Within Twelve Months

        -            3  

Deferred Income Tax Liabilities to be Settled After More Than Twelve Months

        4,146            4,540  
       4,146            4,543  

Deferred Income Tax Assets

            

Deferred Income Tax Assets to be Recovered Within Twelve Months

        (88 )           (113 ) 

Deferred Income Tax Assets to be Recovered After More Than Twelve Months

        (860 )           (398 ) 
       (948 )           (511 ) 

Net Deferred Income Tax Liability

        3,198            4,032  
                       

The deferred income tax assets and liabilities to be settled within twelve months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year.

The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is:

 

Deferred Income Tax Liabilities      PP&E               Risk
Management		               Other               Total  

As at December 31, 2018

        5,450            44            51            5,545  

Charged (Credited) to Earnings

        (927 )           (43 )           (7 )           (977 ) 

Charged (Credited) to OCI

        (25 )           -            -            (25 ) 

As at December 31, 2019

        4,498            1            44            4,543  

Charged (Credited) to Earnings

        (367 )           (1 )           (22 )           (390 ) 

Charged (Credited) to OCI

        (7 )           -            -            (7 ) 

As at December 31, 2020

        4,124            -            22            4,146  
                                                 
Deferred Income Tax Assets      Unused Tax
Losses		               Risk
Management		               Other               Total  

As at December 31, 2018

        (357 )           (1 )           (326 )           (684 ) 

Charged (Credited) to Earnings

        129            -            34            163  

Charged (Credited) to OCI

        3            -            7            10  

As at December 31, 2019

        (225 )           (1 )           (285 )           (511 ) 

Charged (Credited) to Earnings

        (448 )           (12 )           12            (448 ) 

Charged (Credited) to OCI

        14            -            (3 )           11  

As at December 31, 2020

        (659 )           (13 )           (276 )           (948 ) 
                                                 
Net Deferred Income Tax Liabilities                                                         Total  

Net Deferred Income Tax Liabilities as at December 31, 2018

                             4,861  

Charged (Credited) to Earnings

                             (814 ) 

Charged (Credited) to OCI

                             (15 ) 

Net Deferred Income Tax Liabilities as at December 31, 2019

                             4,032  

Charged (Credited) to Earnings

                             (838 ) 

Charged (Credited) to OCI

                             4  

Net Deferred Income Tax Liabilities as at December 31, 2020

                             3,198  
                               

The deferred income tax asset of $36 million (2019 – $nil) represents net deductible temporary differences in the U.S. jurisdiction which has been fully recognized, as the probability of realization is expected due to a forecasted taxable income. No deferred tax liability has been recognized as at December 31, 2020 and 2019 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future.

 

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The approximate amounts of tax pools available, including tax losses, are:

 

As at December 31,

        2020                  2019  

Canada

        6,540            6,113  

United States

        3,117            2,648  
                   9,657                        8,761  
                       

As at December 31, 2020, the above tax pools included $1,682 million (2019 – $696 million) of Canadian federal non-capital losses and $1,084 million (2019 – $188 million) of U.S. federal net operating losses. These losses expire no earlier than 2037.

Also included in the December 31, 2020 tax pools are Canadian net capital losses totaling $85 million (2019 – $188 million), which are available for carry forward to reduce future capital gains. As at December 31, 2020, net capital gains totaling $22 million (2019 – $100 million net capital losses) have been realized, decreasing the net capital loss balance from prior year. The Company has not recognized $254 million (2019 – $262 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.

13. PER SHARE AMOUNTS

 

A) Net Earnings (Loss) Per Share – Basic and Diluted

 

For the years ended December 31,

        2020                  2019                  2018  

Earnings (Loss) From:

                   

Continuing Operations

        (2,379 )           2,194            (2,916 ) 

Discontinued Operations

        -            -            247  

Net Earnings (Loss)

        (2,379 )           2,194            (2,669 ) 

Basic – Weighted Average Number of Shares

        1,228.9            1,228.8            1,228.8  

Dilutive Effect of Cenovus Net Settlement Rights

        -            0.6            0.4  

Diluted – Weighted Average Number of Shares

                    1,228.9                        1,229.4                        1,229.2  

Basic and Diluted Earnings (Loss) Per Share From: ($)

                   

Continuing Operations

        (1.94 )           1.78            (2.37 ) 

Discontinued Operations

        -            -            0.20  
       (1.94 )           1.78            (2.17 ) 
                                    

As at December 31, 2020, 31 million NSRs (2019 – 32 million; 2018 – 34 million) were excluded from the diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceeded the market price of Cenovus’s common shares. These instruments could potentially dilute earnings per share in the future. For further information on the Company’s stock-based compensation plans (see Note 32).

B) Common Share Dividend

The Company temporarily suspended its common share dividend in response to the low global oil price environment. Prior to the suspension, the Company paid common share dividends of $77 million or $0.0625 per common share in the first quarter of 2020, all of which were paid in cash (2019 – $260 million or $0.2125 per common share; 2018 – $245 million or $0.20 per common share). The declaration of dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. The Company’s Board of Directors declared a first quarter dividend of $0.0175 per common share, payable on March 31, 2021, to common shareholders of record as of March 15, 2021.

C) Preferred Share Dividend

Subsequent to the closing of the Arrangement on January 1, 2021, the outstanding Husky preferred shares were exchanged for Cenovus preferred shares (see Note 39). The Company’s Board of Directors declared first quarter dividends for its Cenovus series 1, 2, 3, 5, and 7 first preferred shares, payable on March 31, 2021, in the amount of $8 million.

14. CASH AND CASH EQUIVALENTS

 

 

As at December 31,

        2020                  2019  

Cash

                    368                        108  

Short-Term Investments

        10            78  
       378            186  
                       

 

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15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES

 

 

As at December 31,

      2020              2019    

Accruals

      1,053            1,221    

Prepaids and Deposits

      121            54    

Partner Advances

      175            16    

Trade

      96            212    

Joint Operations Receivables

      35            36    

Other

      8            17    
     1,488            1,556    
                   

16. INVENTORIES  

 

 

As at December 31,

      2020              2019    

Product

                      

Refining and Marketing

      613            874    

Oil Sands

      382            570    

Conventional

      1            1    

Parts and Supplies

      93            87    
     1,089            1,532    
                   

During the year ended December 31, 2020, approximately $9,996 million of produced and purchased inventory was recorded as an expense (2019 – $14,285 million; 2018 – $15,664 million).

As at March 31, 2020, the Company recorded $588 million in non-cash inventory write-downs of its crude oil blend, condensate and refined product inventory. Subsequently, $547 million of inventory that was written down at the end of March was sold and the loss was realized. For the year ended December 31, 2020, the Company reversed $39 million of the inventory write-downs related to March product inventory that was still on hand due to improved refined product and crude oil prices. As at December 31, 2020, the Company recorded a $6 million write-down in refined product inventory.

As at December 31, 2019, the Company recorded a $25 million write-down in refined product inventory. The inventory write-down was realized in 2020.

17. EXPLORATION AND EVALUATION ASSETS

 

 

       Total    

As at December 31, 2018

      785    

Additions

      73    

Exploration Expense (Note 10)

      (82)    

Change in Decommissioning Liabilities

      9    

Exchange Rate Movements and Other

      2    

As at December 31, 2019

      787    

Additions

      48    

Transfers to PP&E (Note 18) (1)

     (47)    

Exploration Expense (Note 10)

      (91)    

Depletion

      (18)    

Change in Decommissioning Liabilities

      5    

Divestitures (Note 8)

      (61)    

As at December 31, 2020

      623    
        

 

(1) 

Includes the $41 million reclassification of the GORR retained in the sale of the Marten Hills assets (see Note 8).  

 

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18. PROPERTY, PLANT AND EQUIPMENT, NET

 

 

     Upstream Assets                                   
      

 Development  

& Production  

  

 

         

 Other  

Upstream  

  

 

         
 Refining  
Equipment  		  
 		          Other (1)              Total    

COST

                       

As at December 31, 2018

      28,046            333            5,632            1,213            35,224    

Adjustment for Change in Accounting Policy (2)

     -            -            (4)            -            (4)    

Additions

      695            -            228            193            1,116    

Change in Decommissioning Liabilities

      340            -            9            5            354    

Exchange Rate Movements and Other

      (9)            -            (288)            3            (294)    

Divestitures (Note 8)

      (40)            -            -            -            (40)    

As at December 31, 2019

      29,032            333            5,577            1,414            36,356    

Additions

      475            -            243            93            811    

Transfers From E&E Assets (Note 17)

      6            41            -            -            47    

Change in Decommissioning Liabilities

      (11)            -            3            2            (6)    

Exchange Rate Movements and Other

      (6)            -            (152)            (1)            (159)    

Divestitures

      (3)            -            -            -            (3)    

As at December 31, 2020

      29,493            374            5,671            1,508            37,046    
                                                    

ACCUMULATED DEPRECIATION,

DEPLETION AND AMORTIZATION

                       

As at December 31, 2018

      3,918            333            1,442            833            6,526    

Adjustment for Change in Accounting Policy (2)

     -            -            (1)            -            (1)    

Depreciation, Depletion and Amortization

      1,735            -            241            75            2,051    

Impairment Charges (Note 10)

      20            -            -            10            30    

Exchange Rate Movements and Other

      31            -            (86)            -            (55)    

Divestitures (Note 8)

      (29)            -            -            -            (29)    

As at December 31, 2019

      5,675            333            1,596            918            8,522    

Depreciation, Depletion and Amortization

      1,768            -            242            109            2,119    

Impairment Charges (Note 10)

      607            -            450            52            1,109    

Exchange Rate Movements and Other

      (22)            -            (93)            -            (115)    

As at December 31, 2020

      8,028            333            2,195            1,079            11,635    
                                                    

CARRYING VALUE

                       

As at December 31, 2018

      24,128            -            4,190            380            28,698    

As at December 31, 2019

      23,357            -            3,981            496            27,834    

As at December 31, 2020

      21,465            41            3,476            429            25,411    
                                                    

 

(1)

Primarily consists of crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2)

Effective January 1, 2019, the Company adopted IFRS 16.

PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:    

 

As at December 31,

      2020                 2019  

Development and Production

      1,807           1,836  

Refining Equipment

      226           172  
     2,033                 2,008  
                          

 

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19. RIGHT-OF-USE ASSETS, NET

 

 

      
 Real   
Estate   		  
 		         
 Railcars   
& Barges   		  
 		         
 Storage   
Assets (1)   		  
 		         

 Refining   

Equipment   

  

 

          Other               Total     

COST

                            

As at January 1, 2019 (2)

     517             63             292             13             9             894     

Additions

      10             436             172             -             6             624     

Terminations

      -             -             (11)             -             -             (11)    

Reclassifications

      (8)            -             -             -             -             (8)    

Re-measurement

      -             (2)            18             (2)            -             14     

Exchange Rate Movements and Other

      (10)            (2)            (7)            (1)            (1)            (21)    

As at December 31, 2019

      509             495             464             10             14             1,492     

Additions

      1             18             22             5             7             53     

Terminations

      -             -             (1)            -             -             (1)    

Modifications

      -             -             1             -             (3)            (2)    

Reclassifications

      (14)            -             -             -             -             (14)    

Re-measurement

      -             (20)            19             -             (1)            (2)    

Exchange Rate Movements and Other

      (1)            (13)            (8)            -             (2)            (24)    

As at December 31, 2020

      495             480             497             15             15             1,502     
                                                               

ACCUMULATED DEPRECIATION

                            

As at January 1, 2019 (2)

     -             -             -             1             -             1     

Depreciation

      29             55             75             2             4             165     

Impairment Charges (Note 10)

      3             -             -             -             -             3     

Terminations

      -             -             (1)            -             -             (1)    

Exchange Rate Movements and Other

      -             -             (1)            -             -             (1)    

As at December 31, 2019

      32             55             73             3             4             167     

Depreciation

      27             86             95             2             5             215     

Impairment Charges (Note 10)

      -             3             -             -             -             3     

Terminations

      -             -             (1)            -             -             (1)    

Exchange Rate Movements and Other

      (1)            (13)            (5)            -             (2)            (21)    

As at December 31, 2020

      58             131             162             5             7             363     
                                                               

CARRYING VALUE

                            

As at January 1, 2019 (2)

     517             63             292             12             9             893     

As at December 31, 2019

      477             440             391             7             10             1,325     

As at December 31, 2020

      437             349             335             10             8             1,139     
                                                               

 

(1)

Includes caverns and tanks.

(2)

Effective January 1, 2019, the Company adopted IFRS 16.

 

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20. OTHER ASSETS

 

 

As at December 31,

     2020              2019    

Intangible Assets

     89            101    

Equity Investments (Note 35A)

     52            52    

Investment in Associate (Note 8)

     97            -    

Net Investment in Finance Leases

     52            30    

Long-Term Receivables and Prepaids

     11            28    

Other

     12            -    
                313                        211    
                  

In 2019, Cenovus entered into an agreement to assume a firm capacity shipper position in a pipeline transportation services agreement from a third party. The fee was recorded as an intangible asset at cost and will be amortized over the life of the contract of approximately 10 years.

21. GOODWILL

 

As at December 31, 2020 and 2019, the carrying amount of goodwill associated with the Company’s Primrose (Foster Creek) CGU and Christina Lake CGU was $1,171 million and $1,101 million, respectively.

For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used to test Cenovus’s goodwill for impairment as at December 31, 2020 are consistent to those disclosed in Note 10. There was no impairment of goodwill as at December 31, 2020.

22. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

 

 

As at December 31,

     2020              2019    

Accruals

     912            1,085    

Trade

     608            954    

Interest

     77            49    

Partner Advances

     175            16    

Employee Long-Term Incentives

     130            60    

Joint Operations Payable

     6            2    

Risk Management

     58            2    

Onerous Contract Provisions

     26            17    

Other

     26            44    
                2,018                        2,229    
                  

23. SHORT-TERM BORROWINGS

 

The Company has uncommitted demand facilities of $1.6 billion in place, of which $600 million may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at December 31, 2020, no amount was drawn on these facilities (December 31, 2019 – $nil) and there were outstanding letters of credit aggregating to $441 million (December 31, 2019 – $364 million).

WRB has uncommitted demand facilities of US$300 million (the Company’s proportionate share – US$150 million) available to cover short-term working capital requirements. As at December 31, 2020, US$190 million was drawn on these facilities, of which the Company’s proportionate share was US$95 million (C$121 million) (December 31, 2019– $nil).

 

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24. LONG-TERM DEBT AND CAPITAL STRUCTURE

 

 

As at December 31,

      Notes       2020                   2019    

Revolving Term Debt (1)

     A       -             265    

U.S. Dollar Denominated Unsecured Notes

      B       7,510             6,492    

Total Debt Principal

        7,510             6,757    

Debt Discounts and Transaction Costs

        (69)            (58)   

Long-Term Debt

              7,441                   6,699    
                     

(1)    Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.

The weighted average interest rate on outstanding debt, including the Company’s proportionate share of the WRB uncommitted demand facilities, for the year ended December 31, 2020 was 4.9 percent (2019 – 5.1 percent).

As at December 31, 2020, the Company is in compliance with all of the terms of its debt agreements.

A) Committed Credit Facilities

Cenovus has in place a committed revolving credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche with maturity dates of November 30, 2022 and November 30, 2023, respectively. In April 2020, the Company added a committed credit facility with capacity of $1.1 billion to further support the Company’s financial resilience in the current market environment. On December 31, 2020, the Company cancelled the $1.1 billion credit facility.

B) U.S. Dollar Denominated Unsecured Notes

The remaining principal amounts of the Company’s U.S. dollar denominated unsecured notes are:

 

     2020          2019  
As at December 31,   

US$ Principal  

Amount  

          

Total C$  

Equivalent  

          

US$ Principal  

Amount  

          

Total C$  

Equivalent  

  

3.00% due August 15, 2022

      500            637            500            650    

3.80% due September 15, 2023

      450            573            450            585    

5.38% due July 15, 2025

      1,000            1,273            -            -    

4.25% due April 15, 2027

      962            1,225            962            1,249    

5.25% due June 15, 2037

      583            742            641            833    

6.75% due November 15, 2039

      1,390            1,770            1,400            1,818    

4.45% due September 15, 2042

      155            198            155            202    

5.20% due September 15, 2043

      58            74            58            75    

5.40% due June 15, 2047

      800            1,018            832            1,080    
     5,898            7,510            4,998            6,492    
                                         

The Company has in place a base shelf prospectus that allows the Company to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus will expire in October 2021. Offerings under the base shelf prospectus are subject to market conditions.

On July 30, 2020, Cenovus completed a public offering in the U.S., under the Company’s U.S. base shelf prospectus, of senior unsecured notes in the aggregate principal of US$1.0 billion due in 2025. As at December 31, 2020, US$3.7 billion is available under the base shelf prospectus for permitted offerings.

In addition, during the year ended December 31, 2020, the Company paid US$81 million to repurchase a portion of its unsecured notes with a principal amount of US$100 million. A gain on the repurchase of $25 million was recorded in finance costs (see Note 6).

C) Mandatory Debt Payments

 

As at December 31, 2020   

US$  

Principal  

Amount  

           Total C$  
Equivalent  		  

2022

      500            637    

2023

      450            573    

2025

      1,000            1,273    

Thereafter

      3,948            5,027    
     5,898            7,510    
                   

 

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D) Capital Structure

Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. Cenovus conducts its business and makes decisions consistent with that of an investment grade company. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, repurchase the Company’s common shares for cancellation, issue new debt, or issue new shares.

Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.

Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may periodically be above the target due to factors such as persistently low commodity prices.

Net Debt to Adjusted EBITDA (1)

 

As at December 31,

      2020            2019            2018  

Short-Term Borrowings

      121          -          -  

Current Portion of Long-Term Debt

      -          -          682  

Long-Term Debt

      7,441          6,699          8,482  

Less: Cash and Cash Equivalents

      (378 )         (186 )         (781 ) 

Net Debt

      7,184          6,513          8,383  

Net Earnings (Loss)

      (2,379 )         2,194          (2,669 ) 

Add (Deduct):

             

Finance Costs

      536          511          628  

Interest Income

      (9 )         (12 )         (19 ) 

Income Tax Expense (Recovery)

      (851 )         (797 )         (920 ) 

Depreciation, Depletion and Amortization

      3,464          2,249          2,131  

Exploration Expense

      91          82          2,123  

Unrealized (Gain) Loss on Risk Management

      56          149          (1,249 ) 

Foreign Exchange (Gain) Loss, Net

      (181 )         (404 )         854  

Re-measurement of Contingent Payment

      (80 )         164          50  

(Gain) Loss on Discontinuance

      -          -          (301 ) 

(Gain) Loss on Divestitures of Assets

      (81 )         (2 )         795  

Other (Income) Loss, Net

      40          9          13  

Adjusted EBITDA

              606                  4,143                  1,436  
                              

Net Debt to Adjusted EBITDA

      11.9x          1.6x          5.8x  
                              

(1)     IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.

Net Debt to Capitalization

 

As at December 31,

      2020              2019              2018    

Net Debt

      7,184            6,513            8,383    

Shareholders’ Equity

      16,707            19,201            17,468    
         23,891                  25,714                25,851    

Net Debt to Capitalization

      30%            25%            32%    
                              

Cenovus also manages its Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit facility agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is well below this limit.

 

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25. LEASE LIABILITIES

 

 

      2020           2019  

Lease Liabilities, Beginning of Year

      1,916          1,494  

Additions

      49          590  

Interest Expense (Note 6)

      87          82  

Lease Payments

      (284 )         (232 ) 

Terminations

      (1 )         (11 ) 

Modifications

      (2 )         -  

Re-measurement

      (2 )         15  

Exchange Rate Movements and Other

      (6 )         (22 ) 

Lease Liabilities, End of Year

      1,757          1,916  
                   

Less: Current Portion

      184          196  

Long-Term Portion

              1,573                  1,720  
                   

The Company has lease liabilities for contracts related to office space, railcars, barges, storage assets, drilling and service rigs, and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions.

 

For the years ended December 31,

      2020        2019  

Variable Lease Payments

                  16                    19  

Short-Term Lease Payments

      6        13  

The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are leases with terms of twelve months or less.

The Company has included extension options in the calculation of lease liabilities where the Company has the right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company does not have any significant termination options and the residual amounts are not material.

26. CONTINGENT PAYMENT

 

 

      2020           2019  

Contingent Payment, Beginning of Year

              143                  132  

Re-measurement (1)

     (80 )         164  

Liabilities Settled or Payable

      -          (153 ) 

Contingent Payment, End of Year

      63          143  
                   

Less: Current Portion

      36          79  

Long-Term Portion

      27          64  
                   

(1)     Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.

In connection with the acquisition (the “Acquisition in 2017”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. There are no maximum payment terms.

The contingent payment is accounted for as a financial option. The fair value is estimated by calculating the present value of the future expected cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate. The contingent payment is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. As at December 31, 2020, no amount was payable under this agreement (2019 – $14 million).

 

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27. DECOMMISSIONING LIABILITIES

 

The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal.

The aggregate carrying amount of the obligation is:

 

      2020           2019  

Decommissioning Liabilities, Beginning of Year

      1,235          875  

Liabilities Incurred

      14          3  

Liabilities Settled

      (42 )         (52 ) 

Liabilities Disposed

      (2 )         (8 ) 

Change in Estimated Future Cash Flows

      13          21  

Change in Discount Rate

      (28 )         339  

Unwinding of Discount on Decommissioning Liabilities (Note 6)

      57          58  

Foreign Currency Translation

      1          (1 ) 

Decommissioning Liabilities, End of Year

              1,248                  1,235  
                   

As at December 31, 2020, the undiscounted amount of estimated future cash flows required to settle the obligation is $4,953 million (2019 – $5,173 million), which has been discounted using a credit-adjusted risk-free rate of 5.0 percent (2019 – 4.9 percent) and an inflation rate of two percent (2019 – two percent). Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $40 million to $45 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning liabilities over the estimated life of the reserves and an increase in cost estimates.

Sensitivities

Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:

 

            2020          2019  
     Sensitivity                 

As at December 31,

      Range        Increase            Decrease            Increase       Decrease  

Credit-Adjusted Risk-Free Rate

      ± one percent        (228 )         313          (236 )      332  

Inflation Rate

      ± one percent        321            (235 )           340       (243 ) 

28. OTHER LIABILITIES

 

 

As at December 31,

      2020            2019  

Employee Long-Term Incentives

      33          103  

Pension and Other Post-Employment Benefit Plan (Note 29)

      91          73  

Onerous Contract Provisions

      39          46  

Other

      18          19  
             181                  241  
                   

 

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29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS

 

 

The Company provides employees with a pension that includes either a defined contribution or defined benefit component and other post-employment benefit plan. Most of the employees participate in the defined contribution pension. Employees who meet certain criteria may elect to move from the current defined contribution component to a defined benefit component for their future service.

The defined benefit pension provides pension benefits at retirement based on years of service and final average earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides certain retired employees with health care and dental benefits until age 65 and life insurance benefits.

The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial regulator at least every three years. The most recently filed valuation was dated December 31, 2019 and the next required actuarial valuation will be as at December 31, 2022.

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:

 

     Pension Benefits          OPEB  

As at December 31,

      2020            2019            2020            2019  

Defined Benefit Obligation

                  

Defined Benefit Obligation, Beginning of Year

      158          167          22          21  

Current Service Costs

      13          11          1          1  

Interest Costs (1)

     5          6          -          1  

Benefits Paid

      (6 )         (36 )         (2 )         (2 ) 

Plan Participant Contributions

      2          2          -          -  

Re-measurements:

                  

(Gains) Losses From Experience Adjustments

      1          (4 )         (2 )         -  

(Gains) Losses From Changes in Financial Assumptions

      15          12          1          1  

Defined Benefit Obligation, End of Year

      188          158          20          22  

Plan Assets

                  

Fair Value of Plan Assets, Beginning of Year

      107          113          -          -  

Employer Contributions

      6          9          -          -  

Plan Participant Contributions

      2          2          -          -  

Benefits Paid

      (5 )         (35 )         -          -  

Interest Income (1)

     2          3          -          -  

Re-measurements:

                  

Return on Plan Assets (Excluding Interest Income)

      5          15          -          -  

Fair Value of Plan Assets, End of Year

      117          107          -          -  

Pension and OPEB (Liability) (2)

     (71 )         (51 )         (20 )         (22 ) 
                                         

 

(1)

Based on the discount rate of the defined benefit obligation at the beginning of the year.

(2)

Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.

The weighted average duration of the defined benefit pension and OPEB obligations are 17.4 years and 13.3 years, respectively.

B) Pension and OPEB Costs

 

     Pension Benefits         

OPEB

  

For the years ended December 31,

      2020            2019            2018            2020            2019            2018  

Defined Benefit Plan Cost

                            

Current Service Costs

      13          11          13          1          1          1  

Past Service Costs – Curtailments

      -          -          (2 )         -          -          -  

Net Interest Costs

      3          3          3          -          1          1  

Re-measurements:

                            

Return on Plan Assets (Excluding Interest Income)

      (5 )         (15 )         7          -          -          -  

(Gains) Losses From Experience Adjustments

      1          (4 )         -          (2 )         -          -  

(Gains) Losses From Changes in Financial Assumptions

      15          12          -          1          1          (1 ) 

Defined Benefit Plan Cost (Recovery)

      27          7          21          -          3          1  

Defined Contribution Plan Cost

      22          21          22          -          -          -  

Total Plan Cost

      49          28          43          -          3          1  
                                                               

 

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C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.

The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced monthly, if necessary. The asset allocation structure targets an investment of 25 percent to 70 percent in equity securities, 25 percent to 35 percent in fixed income assets, zero percent to 15 percent in real estate assets, zero percent to 10 percent in listed infrastructure assets, zero percent to 10 percent in emerging market debts and zero percent to 10 percent in cash and cash equivalents.

The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods.

The fair value of the plan assets is:

 

As at December 31,

      2020            2019  

Equity Funds

      58          59  

Fixed Income Funds

      35          35  

Real Estate Funds

      6          -  

Listed Infrastructure Funds

      8          9  

Emerging Market Debt Funds

      7          -  

Non-Invested Assets

      1          2  

Cash and Cash Equivalents

      2          2  
     117          107  
                   

Fair value of the equity, fixed income and listed infrastructure assets are based on the trading price of the underlying funds (Level 1). The fair value of the real estate fund reflects the appraisal valuation for each property investment (Level 2). The fair value of the non-invested assets is the discounted value of the expected future payments (Level 3).

The defined benefit plan does not hold any direct investment in Cenovus shares.

D) Funding

The defined benefit pension is funded in accordance with federal and provincial government pension legislation, where applicable. Contributions are made to trust funds administered by an independent trustee. The Company’s contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at December 31, 2019, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors.

Employees participating in the defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The expected employer contributions for the year ended December 31, 2021 are $10 million for the defined benefit pension plan. The OPEB is funded on an as required basis.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:

 

     Pension Benefits         

OPEB

 

For the years ended December 31,

      2020            2019            2018            2020            2019            2018  

Discount Rate

      2.50 %         3.00 %         3.50 %         2.50 %         3.00 %         3.50 % 

Future Salary Growth Rate

      3.97 %         3.94 %         3.88 %         4.94 %         5.08 %         5.08 % 

Average Longevity (years)

      88.3          88.2          88.2          88.2          88.2          88.1  

Health Care Cost Trend Rate

      N/A          N/A          N/A          6.00 %         6.00 %         6.00 % 

The discount rates are determined with reference to market yields on high quality corporate debt instruments of similar duration to the benefit obligations at the end of the reporting period.

 

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Sensitivities

The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:

 

     2020    

 

    2019  
As at December 31,    Increase           Decrease             Increase           Decrease    

One Percent Change:

                  

Discount Rate

      (31 )         40          (25 )         32  

Future Salary Growth Rate

      4          (4 )         3          (3 ) 

Health Care Cost Trend Rate

      1          (1 )         1          (1 ) 

One Year Change in Assumed Life Expectancy

      4          (4 )         3          (3 ) 

The sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, the changes in some assumptions may be correlated. The same methodologies have been used to calculate the sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied when calculating the defined benefit pension liability recorded on the Consolidated Balance Sheets.

F) Risks

Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity risk, interest rate risk, investment risk and salary risk.

Longevity Risk

The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality of plan participants both during and after their employment. An increase in the life expectancy of participants will increase the defined benefit plan obligation.

Interest Rate Risk

A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially offset by an increase in the return on debt holdings.

Investment Risk

The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than in debt instruments and real estate.

Salary Risk

The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation.

30. SHARE CAPITAL

 

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles. Prior to the close of the Arrangement, Cenovus’s articles were amended effective December 30, 2020 to create the Cenovus series 1, 2, 3, 4, 5, 6, 7 and 8 first preferred shares.

B) Issued and Outstanding

 

     2020             2019  
As at December 31,   

Number of
Common
Shares

(thousands)

           Amount             

Number of
Common
Shares

(thousands)

           Amount  

Outstanding, Beginning of Year

      1,228,828          11,040           1,228,790          11,040  

Common Shares Issued Under Stock Option Plan (Note 32)

      42          -           38          -  

Outstanding, End of Year

      1,228,870          11,040           1,228,828          11,040  
                                          

There were no preferred shares outstanding as at December 31, 2020 (2019 – nil).

 

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As at December 31, 2020, there were 27 million (2019 – 26 million) common shares available for future issuance under the stock option plan.

Subsequent to December 31, 2020, the Company issued common shares and first preferred shares in connection to the Arrangement that closed on January 1, 2021 (see Note 39).

C) Paid in Surplus

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) under the plan of arrangement into two independent energy companies, Encana (now known as Ovintiv Inc.) and Cenovus (pre-arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 32A.

 

      

 Pre-
Arrangement
Earnings		  
 
 		         
 Stock-Based
Compensation		  
 		          Total  

As at December 31, 2018

      4,086          281          4,367  

Stock-Based Compensation Expense

      -          10          10  

As at December 31, 2019

      4,086          291          4,377  

Stock-Based Compensation Expense

      -          14          14  

As at December 31, 2020

      4,086          305          4,391  
                              

31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

 

 

 

      

 Defined
Benefit
Pension Plan		  
 
 		         

 Private
Equity
Instruments		  
 
 		         


 Foreign
Currency
Translation
Adjustment		  
 
 
 		          Total  

As at December 31, 2018

      (7 )         15          1,030          1,038  

Other Comprehensive Income (Loss), Before Tax

      6          14          (228 )         (208 ) 

Income Tax

      (1 )         (2 )         -          (3 ) 

As at December 31, 2019

      (2 )         27          802          827  

Other Comprehensive Income (Loss), Before Tax

      (10 )         -          (44 )         (54 ) 

Income Tax

      2          -          -          2  

As at December 31, 2020

      (10 )         27          758          775  
                                         

32. STOCK-BASED COMPENSATION PLANS

 

 

A) Employee Stock Option Plan

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market value for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.

Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising the option, gives the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the excess of the market price received from the sale of the common shares over the exercise price of the option.

The NSRs vest and expire under the same terms and conditions as the underlying options.

 

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Net Settlement Rights

The weighted average unit fair value of NSRs granted during the year ended December 31, 2020 was $2.27 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

 

Risk-Free Interest Rate

      1.19 % 

Expected Dividend Yield

      1.77 % 

Expected Volatility (1)

     29.74 % 

Expected Life (years)

      5.00  
(1)

Expected volatility has been based on historical share volatility of the Company and comparable industry peers.

The following tables summarize information related to the NSRs:

 

For the year ended December 31, 2020

     

 Number of
NSRs

(thousands)

  
 

 

       

 Weighted

Average

Exercise

Price ($)

  

 

 

 

Outstanding, Beginning of Year

      31,528          22.61  

Granted

      5,783          11.73  

Exercised

      (42 )         9.48  

Forfeited

      (416 )         23.52  

Expired

      (6,256 )         32.60  

Outstanding, End of Year

      30,597          18.52  
                   

 

  

 

Outstanding NSRs

 

        Exercisable NSRs  

As at December 31, 2020

Range of Exercise Price ($ )

     

 Number of
NSRs

(thousands)

  
 

 

             




 Weighted
Average
Remaining
Contractual
Life

(years)

  
 
 
 
 

 

             


 Weighted
Average
Exercise

Price ($)

  
 
 

 

             

Number
of NSRs

(thousands

  
  

) 

             


 Weighted
Average
Exercise
Price ($)		  
 
 
 

5.00 to 9.99

      2,796          4.2          9.48          1,596          9.48  

10.00 to 14.99

      12,921          5.2          12.27          4,189          13.53  

15.00 to 19.99

      2,691          2.3          19.47          2,691          19.47  

20.00 to 24.99

      3,078          1.1          22.26          3,078          22.26  

25.00 to 29.99

      8,540          0.1          28.37          8,540          28.37  

30.00 to 34.99

      571          0.5          32.27          571          32.27  
     30,597          2.9          18.52          20,665          21.94  
                                                    

The Arrangement on January 1, 2021 resulted in the accelerated vesting of outstanding NSRs held by non-executive employees and certain non-executive officers of the Company. In accordance with their terms, 2,738 thousand additional NSRs vested and were exercisable as a result of the accelerated vesting on January 1, 2021.

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are time-vested whole-share units that entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible to vest is determined by a multiplier that ranges from zero percent to 200 percent and is based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

The Company has recorded a liability of $65 million as at December 31, 2020 (2019 – $53 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. The Arrangement on January 1, 2021 resulted in the accelerated vesting of outstanding PSUs held by non-executive employees and certain non-executive officers of the Company. As a result, the intrinsic value was $51 million as at December 31, 2020. In accordance with their terms, 7,055 thousand PSUs will be settled, in cash, subsequent to December 31, 2020 based on the 30-day volume weighted average trading price prior to the date of closing. The intrinsic value of vested PSUs was $nil as at December 31, 2019.

 

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The following table summarizes the information related to the PSUs held by Cenovus employees:

 

For the year ended December 31, 2020

     

 Number of
PSUs
(thousands		  
 
) 

Outstanding, Beginning of Year

      6,912  

Granted

      3,846  

Vested and Paid Out

      (1,223 ) 

Cancelled

      (449 ) 

Units in Lieu of Dividends

      198  

Outstanding, End of Year

      9,284  
        

C) Restricted Share Units

Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs generally vest after three years.

RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period they occur.

The Company has recorded a liability of $61 million as at December 31, 2020 (2019 – $63 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. The Arrangement on January 1, 2021 resulted in the accelerated vesting of outstanding RSUs held by employees and certain non-executive officers of the Company. As a result, the intrinsic value was $60 million as at December 31, 2020. In accordance with their terms, 8,237 thousand RSUs will be settled, in cash, subsequent to December 31, 2020 based on the 30-day volume weighted average trading price prior to the date of closing. The intrinsic value of vested RSUs was $nil as at December 31, 2019.

The following table summarizes the information related to the RSUs held by Cenovus employees:

 

For the year ended December 31, 2020

     

 Number of
RSUs
(thousands		  
 
) 

Outstanding, Beginning of Year

      8,372  

Granted

      2,686  

Vested and Paid Out

      (2,606 ) 

Cancelled

      (234 ) 

Units in Lieu of Dividends

      212  

Outstanding, End of Year

      8,430  
        

D) Deferred Share Units

Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

The Company has recorded a liability of $10 million as at December 31, 2020 (2019 – $16 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant. In connection with the Arrangement, the termination of a DSU holder that is a Cenovus director or employee will result in the settlement and redemption of DSUs, in cash based on the five day volume weighted average trading price prior to the date of redemption, in accordance with the terms of the related DSU Plan.

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

 

For the year ended December 31, 2020

     

 Number of
DSUs
(thousands)		  
 
 

Outstanding, Beginning of Year

      1,237  

Granted to Directors

      288  

Granted

      30  

Units in Lieu of Dividends

      33  

Redeemed

      (255 ) 

Outstanding, End of Year

      1,333  
        

 

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E) Total Stock-Based Compensation

 

For the years ended December 31,

      2020            2019            2018  

Net Settlement Rights

      11          9          6  

Performance Share Units

      19          15          (6 ) 

Restricted Share Units

      23          34          9  

Deferred Share Units

      (4 )         9          -  

Stock-Based Compensation Expense

      49          67          9  

Stock-Based Compensation Costs Capitalized

      16          20          4  
     65          87          13  
                              

33. EMPLOYEE SALARIES AND BENEFIT EXPENSES

 

 

 

For the years ended December 31,

      2020            2019            2018  

Salaries, Bonuses and Other Short-Term Employee Benefits

      605          567          580  

Post-Employment Benefits

      33          29          30  

Stock-Based Compensation Expense (Note 32)

      49          67          9  

Other Long-Term Incentive Benefits

      (4 )         31          -  

Termination Benefits

      9          6          63  
     692          700          682  
                              

Stock-based compensation includes the costs recorded during the year associated with NSRs, PSUs, RSUs and DSUs.

34. RELATED PARTY TRANSACTIONS

 

 

Key Management Compensation

Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is:

 

For the years ended December 31,

      2020            2019            2018  

Salaries, Director Fees and Short-Term Benefits

      21          24          20  

Post-Employment Benefits

      3          2          3  

Stock-Based Compensation

      15          22          5  

Other Long-Term Incentive Benefits

      1          1          -  

Termination Benefits

      6          -          9  
     46          49          37  
                              

Post-employment benefits represent the present value of future pension benefits earned during the year.

35. FINANCIAL INSTRUMENTS

 

 

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, net investment in finance leases, accounts payable and accrued liabilities, risk management assets and liabilities, investments in the equity of private companies, long-term receivables, lease liabilities, contingent payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of long-term receivables and net investment in finance leases approximate their carrying amounts due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair value of long-term debt has been determined based on the period-end trading prices on the secondary market (Level 2). As at December 31, 2020, the carrying value of Cenovus’s long-term debt was $7,441 million and the fair value was $8,608 million (2019 carrying value – $6,699 million; fair value – $7,610 million).

 

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Equity investments classified at FVOCI comprise equity investments in private companies. The Company classifies certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available.

The following table provides a reconciliation of changes in the fair value of private equity investments classified at FVOCI:

 

       2020            2019  

Fair Value, Beginning of Year

      52          38  

Change in Fair Value (1)

     -          14  

Fair Value, End of Year

      52          52  
                   

 

(1)

Changes in fair value are recorded in OCI.

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil swaps, futures, natural gas futures, and if entered into, crude oil options, condensate futures and swaps, foreign exchange swaps, interest rate swaps and cross currency interest rate swaps. Crude oil, condensate and, if entered into, natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and the fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including interest rate yield curves (Level 2). The fair value of cross currency interest rate swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2).

Summary of Unrealized Risk Management Positions

 

     2020     2019  
     Risk Management     Risk Management  
As at December 31,    Asset           Liability           Net     Asset      Liability      Net  

Crude Oil, Natural Gas and Condensate

      5            58            (53 )      5        2        3  

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

 

As at December 31,

      2020            2019  

Level 2 – Prices Sourced From Observable Data or Market Corroboration

      (53 )         3  

Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.

The following table summarizes the changes in the fair value of Cenovus’s risk management assets and liabilities:

 

       2020            2019  

Fair Value of Contracts, Beginning of Year

      3          160  

Fair Value of Contracts Realized During the Year

      252          7  

Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year

      (308 )         (156 ) 

Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts

      -          (8 ) 

Fair Value of Contracts, End of Year

      (53 )         3  
                   

Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset.

 

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The following table provides a summary of the Company’s offsetting risk management positions:

 

     2020    2019  
     Risk Management    Risk Management  

As at December 31,

      Asset            Liability            Net            Asset            Liability            Net  

Recognized Risk Management Positions

                            

Gross Amount

      70          123          (53 )         13          10          3  

Amount Offset

      (65 )         (65 )         -          (8 )         (8 )         -  

Net Amount per Consolidated Financial Statements

      5          58          (53 )         5          2          3  
                                                               

The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.

Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management receivables on a particular day. As at December 31, 2020, $59 million was pledged as cash collateral (2019 – $nil).

C) Fair Value of Contingent Payment

The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian to U.S. foreign exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 2.0 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2020, the fair value of the contingent payment was estimated to be $63 million (2019 – $143 million).

As at December 31, 2020, average WCS forward pricing for the remaining term of the contingent payment is $42.93 per barrel. The average implied volatility of WTI options and the Canadian to U.S. foreign exchange rate options used to value the contingent payment were 35.6 percent and 6.8 percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

 

As at December 31, 2020

      Sensitivity Range        Increase            Decrease  

WCS Forward Prices

      ± $5.00 per barrel        (41 )         32  

WTI Option Volatility

      ± five percent        (18 )         17  

Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility

      ± five percent        7            (10 ) 

As at December 31, 2019

      Sensitivity Range        Increase            Decrease  

WCS Forward Prices

      ± $5.00 per barrel        (129 )         80  

WTI Option Volatility

      ± five percent        (45 )         42  

Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility

      ± five percent        10            (19 ) 

D) Earnings Impact of (Gains) Losses From Risk Management Positions

 

For the years ended December 31,

      2020            2019            2018  

Realized (Gain) Loss (1)

     252          7          1,554  

Unrealized (Gain) Loss (2)

     56          149          (1,249 ) 

(Gain) Loss on Risk Management From Continuing Operations

      308          156          305  
                              

 

(1)

Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

(2)

Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.

 

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36. RISK MANAGEMENT

 

 

Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk.

To manage exposure to interest rate volatility, the Company may periodically enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2020, there were no interest rate, foreign exchange or cross currency interest rate swap contracts outstanding.

To manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus, the Company may periodically enter into financial positions as a part of ongoing operations to market the Company’s production and physical inventory positions of crude oil and condensate volumes. The Company has entered into risk management positions to help capture the incremental margin expected to be received in future periods at the time products will be sold. To mitigate overall exposure to the fluctuations in commodity prices, the Company may also enter into financial positions to protect the near-term and future cash flows. As at December 31, 2020, the fair value of financial positions was a net liability of $53 million and primarily consisted of crude oil and condensate instruments.

Net Fair Value of Risk Management Positions

 

As at December 31, 2020

     
 Notional
Volumes 		  
(1) (2) 		          Terms (3)           
 Weighted
Average Price 
(1) (2) 		         

Fair Value
Asset

(Liability

  
 

) 

Crude Oil and Condensate Contracts

                  

WTI Fixed - Sell

      19.6 MMbbls          January 2021 - June 2022          US$43.99/bbl          (113 ) 

WTI Fixed - Buy

      11.7 MMbbls          February 2021 - June 2022          US$44.55/bbl          59  

Other Financial Positions (4)

                    1  

Total Fair Value

                     (53 ) 
                       

 

(1)

Million barrels (“MMbbls”). Barrel (“bbl”).

(2)

Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3)

Contract terms represents averages for various individual contracts with different terms and range from one to twenty-three months.

(4)

Other financial positions consist of risk management positions related to WCS and condensate differential contracts, Belvieu and natural gas fixed contracts and the Company’s Refining and Marketing segment.

A) Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.

The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.

Crude Oil – The Company has used commodity futures and swaps, basis price risk management contracts, and costless collars to partially mitigate its exposure to the commodity price risk on its crude oil sales and to protect both near-term and future cash flows. Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials and to manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus. In addition, the Company has entered into risk management positions to help mitigate the risk to incremental margin expected to be received in future periods at the time products will be sold.

Condensate – The Company has used commodity futures and swaps, as well as basis price risk management contracts to partially mitigate its exposure to the commodity price risk on its condensate purchases.

Natural Gas – The Company has used fixed price and basis instruments to partially mitigate its natural gas commodity price risk.

 

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Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

 

As at December 31, 2020

    Sensitivity Range    Increase         Decrease

Crude Oil Commodity Price

   

± US$5.00 per bbl Applied to WTI and Condensate Hedges

    (44)       44

Crude Oil Differential Price

   

± US$2.50 per bbl Applied to Differential Hedges Tied to Production

    (2)       2

As at December 31, 2019

    Sensitivity Range    Increase         Decrease

Crude Oil Commodity Price

   

± US$5.00 per bbl Applied to WTI and Condensate Hedges

    3       (3)

Crude Oil Differential Price

   

± US$2.50 per bbl Applied to Differential Hedges Tied to Production

    5         (5)

B) Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.

As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2020, Cenovus had US$5,898 million in U.S. dollar debt issued from Canada (2019 – US$4,998 million). In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

 

For the years ended December 31,

    2020     2019 

$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate

    300     250 

$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate

    (300)    (250)
  

 

   

 

C) Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. To manage exposure to interest rate volatility, the Company periodically enters into interest rate swap contracts. As at December 31, 2020, Cenovus had no interest rate swap contracts outstanding (2019 – $nil). To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2020, Cenovus had no cross currency interest rate swap contracts outstanding (2019 – $nil).

As at December 31, 2020, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $1 million (2019 – $3 million; 2018 – $nil). This assumes the amount of fixed and floating debt remains unchanged from respective balance sheet dates.

D) Credit Risk

Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee and the Board of Directors designed to ensure that its credit exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.

Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, net investment in finance leases, risk management assets, and long-term receivables is the total carrying value.

 

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As at December 31, 2020, approximately 98 percent of the Company’s accruals, joint operations, trade receivables and net investment in finance leases were with investment grade counterparties (2019 – 97 percent), and as at December 31, 2020 and 2019, substantially all of the Company’s accounts receivable were outstanding less than 60 days. The average expected credit loss on the Company’s accruals, joint operations, trade receivables and net investment in finance leases was 0.5 percent as at December 31, 2020 (2019 – 0.3 percent). As at December 31, 2020, Cenovus had one counterparty (2019 – one counterparty) whose net settlement position individually accounted for more than 10 percent of the fair value of the Company’s accruals, joint operations, trade receivables and net investment in finance leases.

E) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 24, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn capacity on its committed credit facility and uncommitted demand facilities as well as availability under its base shelf prospectus. As at December 31, 2020, Cenovus had $378 million in cash and cash equivalents, $4.5 billion available on its committed credit facility, $1.1 billion available on its uncommitted demand facilities, of which $600 million may be drawn for general purposes, or the full amount can be available to issue letters of credit. A further US$55 million representing the Company’s available proportionate share of the WRB uncommitted demand facilities is available. In addition, Cenovus has unused capacity of US$3.7 billion under its base shelf prospectus, the availability of which is dependent on market conditions.

On January 1, 2021, with the close of the Arrangement, Cenovus obtained access to additional sources of capital (see Note 39).

Undiscounted cash outflows relating to financial liabilities are:

 

As at December 31, 2020    Less than 1
Year		            Years 2 and 3            Years 4 and 5            Thereafter            Total  

Accounts Payable and Accrued Liabilities

      2,018           -           -           -           2,018  

Short-Term Borrowings (1)

     121           -           -           -           121  

Long-Term Debt (1)

     385           1,965           1,966           8,627           12,943  

Contingent Payment (2)

     36           28           -           -           64  

Lease Liabilities (1)

     254           445           365           1,412           2,476  
As at December 31, 2019    Less than 1
Year		            Years 2 and 3            Years 4 and 5            Thereafter            Total  

Accounts Payable and Accrued Liabilities

      2,229           -           -           -           2,229  

Long-Term Debt (1)

     344           1,338           1,465           9,326           12,473  

Contingent Payment (2)

     79           69           -           -           148  

Lease Liabilities (1)

     277           466           410           1,544           2,697  

(1) Principal and interest, including current portion.

(2) Refer to Note 35C for fair value assumptions.

 

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37. SUPPLEMENTARY CASH FLOW INFORMATION

 

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

 

For the years ended December 31,

      2020                   2019                   2018    

Interest Paid

      381             457             564    

Interest Received

      5             12             19    

Income Taxes Paid

                  18                         17                         116    

The following table provides a reconciliation of cash flows arising from financing activities:

 

      
 Dividends  
Payable  		  
 		         
 Short-Term  
Borrowings  		  
 		         
 Long-Term  
Debt  		  
 		         
 Lease  
Liabilities  		  
 

As at December 31, 2017

      -            -            9,513            -    

Changes From Financing Cash Flows:

                  

Repayment of Long-Term Debt

      -            -            (1,144)           -    

Net Issuance (Repayment) of Revolving Long-Term Debt

      -            -            (20)           -    

Dividends Paid

      (245)           -            -            -    

Non-Cash Changes:

                  

Dividends Declared

      245            -            -            -    

Foreign Exchange (Gain) Loss

      -            -            817            -    

Finance Costs

      -            -            (2)           -    

As at December 31, 2018

      -            -            9,164            -    

Adjustment for Change in Accounting Policy (1)

     -            -            -            1,494    

Changes From Financing Cash Flows:

                  

Dividends Paid

      (260)           -            -            -    

Repayment of Long-Term Debt

      -            -            (2,279)           -    

Net Issuance (Repayment) of Revolving Long-Term Debt

      -            -            276            -    

Principal Repayment of Leases

      -            -            -            (150)   

Non-Cash Changes:

                  

Dividends Declared

      260            -            -            -    

Foreign Exchange (Gain) Loss

      -            -            (399)           (23)   

Gain on Repurchase of Debt and Amortization of Debt Issuance Costs

      -            -            (63)           -    

Lease Additions

      -            -            -            590    

Re-measurement of Lease Liabilities

      -            -            -            15    

Lease Terminations

      -            -            -            (11)   

Other

      -            -            -            1    

As at December 31, 2019

      -            -            6,699            1,916    

Changes From Financing Cash Flows:

                  

Dividends Paid

      (77)           -            -            -    

Issuance (Repayment) of Short-Term Borrowings

      -            117            -            -    

Issuance of Long-Term Debt

      -            -            1,326            -    

Repayment of Long-Term Debt

      -            -            (112)           -    

Net Issuance (Repayment) of Revolving Long-Term Debt

      -            -            (220)           -    

Principal Repayment of Leases

      -            -            -            (197)   

Non-Cash Changes:

                         

Dividends Declared

      77            -            -            -    

Foreign Exchange (Gain) Loss

      -            4            (231)           (6)   

Gain on Repurchase of Debt and Amortization of Debt Issuance Costs

      -            -            (20)           -    

Lease Additions

      -            -            -            49    

Lease Terminations

      -            -            -            (1)   

Lease Modifications

      -            -            -            (2)   

Re-measurement of Lease Liabilities

      -            -            -            (2)   

Other

      -            -            (1)           -    

As at December 31, 2020

      -            121          7,441            1,757    
                                         

 

(1)

Effective January 1, 2019, the Company adopted IFRS 16.

 

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38. COMMITMENTS AND CONTINGENCIES

 

A) Commitments

Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts recorded in the Consolidated Balance Sheets.

 

As at December 31, 2020

      1 Year                   2 Years                   3 Years                   4 Years                   5 Years                   Thereafter                   Total    

Transportation and Storage (1)

     1,014             954             1,341             1,444             1,107             15,537             21,397    

Real Estate (2)

     34             36             38             41             44             604             797    

Capital Commitments

      1             2             -             -             -             -             3    

Other Long-Term Commitments

      104             45             32             32             24             85             322    

Total Payments (3)

     1,153             1,037             1,411             1,517             1,175             16,226             22,519    
                                                                                

As at December 31, 2019

      1 Year                   2 Years                   3 Years                   4 Years                   5 Years                   Thereafter                   Total    

Transportation and Storage (1)

     1,005             959             1,026             1,456             1,381             15,672             21,499    

Real Estate (2)

     35             36             38             39             42             662             852    

Other Long-Term Commitments

      104             44             36             34             28             108             354    

Total Payments (3)

     1,144             1,039             1,100             1,529             1,451             16,442               22,705    
                                                                                

 

(1)

Includes transportation commitments of $14 billion (2019 – $13 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the date of commencement.

(2)

Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(3)

Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest.

Transportation and storage commitments include future commitments relating to storage tank leases of $31 million, that have not yet commenced.

As at December 31, 2020, there were outstanding letters of credit aggregating to $441 million issued as security for performance under certain contracts (2019 – $364 million).

In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 36 and commitments related to the Arrangement are disclosed in Note 39.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.

Decommissioning Liabilities

Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of $1,248 million, based on current legislation and estimated costs, related to its upstream properties, refining facilities and the crude-by-rail terminal. Actual costs may differ from those estimated due to changes in legislation and changes in costs.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

Contingent Payment

In connection with the Acquisition in 2017, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. As at December 31, 2020, the estimated fair value of the contingent payment was $63 million (2019 – $143 million) (see Note 26).

 

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39. SUBSEQUENT EVENT

 

 

Cenovus and Husky Combine to Create a New Integrated Energy Company

A) Summary of the Acquisition

On October 25, 2020, Cenovus announced that it had entered into a definitive agreement to combine with Husky. The transaction was accomplished through a plan of arrangement pursuant to which Cenovus acquired all the issued and outstanding common shares of Husky in exchange for common shares and common share purchase warrants of Cenovus. In addition, all of the issued and outstanding Husky preferred shares were exchanged for Cenovus preferred shares with substantially identical terms. The Arrangement closed on January 1, 2021.

The Arrangement will combine oil sands and heavy oil assets with extensive transportation, storage and logistics and downstream infrastructure, creating opportunities to optimize the margin captured across the heavy oil value chain. The combined company will be largely integrated, reducing exposure to Alberta heavy oil price differentials while maintaining exposure to global commodity prices.

The Arrangement was accounted for using the acquisition method pursuant to IFRS 3, “Business Combinations”. Under the acquisition method, assets and liabilities are measured at their estimated fair value on the date of acquisition with the exception of income tax, stock-based compensation, lease liabilities and ROU assets. The total consideration was allocated to the tangible and intangible assets acquired and liabilities assumed.

B) Purchase Price Allocation

Cenovus acquired all the issued and outstanding Husky common shares in consideration for the issuance of 0.7845 Cenovus common shares plus 0.0651 Cenovus warrants for each Husky common share. Cenovus issued 788.5 million Cenovus common shares with a fair value of $6.1 billion, based on the December 31, 2020 closing share price of $7.75, as reported on the TSX. In addition, 65.4 million common share purchase warrants were issued. Each whole warrant entitles the holder to acquire one Cenovus common share for a period of five years at an exercise price of $6.54 per share. The fair value of the warrants was estimated to be $216 million. Cenovus also acquired all the issued and outstanding Husky preferred shares in exchange for 36.0 million Cenovus first preferred shares with substantially identical terms and a fair value of $519 million. The outstanding Husky stock options were also exchanged for Cenovus replacement stock options. Each replacement stock option entitles the holder to acquire 0.7845 of a Cenovus common share at an exercise price per share of a Husky stock option divided by 0.7845. The fair value of the replacement stock options was estimated to be $9 million.

The preliminary purchase price allocation is based on Management’s best estimate of the assets acquired and liabilities assumed. Upon finalizing the value of net assets acquired, adjustments may be required.

The following table summarizes the details of the consideration and the recognized amounts of assets acquired and liabilities assumed at the date of the acquisition.

 

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As at

     
 January 1,
2021		  
 

Consideration

   

Common Shares

      6,111  

Preferred Shares

      519  

Share Purchase Warrants

      216  

Replacement Stock Options

      9  

Non-Controlling Interest

      11  

Total Consideration and Non-Controlling Interest

      6,866  
        

Identifiable Assets Acquired and Liabilities Assumed

   

Cash

      735  

Restricted Cash

      164  

Accounts Receivable and Accrued Revenues

      1,272  

Inventories

      1,118  

Property, Plant and Equipment, Intangible Assets and Deferred Income Tax Assets

      15,227  

Right-of-Use Assets

      1,137  

Long-Term Income Tax Receivable

      202  

Other Assets

      200  

Investments in Joint Ventures

      457  

Accounts Payable and Accrued Liabilities

      (2,224 ) 

Income Tax Payable

      (59 ) 

Current Portion of Long-Term Debt

      (40 ) 

Long-Term Debt

      (6,602 ) 

Lease Liabilities

      (1,447 ) 

Decommissioning Liabilities

      (2,835 ) 

Other Liabilities

      (439 ) 

Total Identifiable Net Assets

      6,866  
        

The fair value of trade and other receivables acquired as part of the acquisition is $1.1 billion, with a gross contractual amount of $1.2 billion. As of the acquisition date, the best estimate of the contractual cash flows not expected to be collected is $36 million.

Cenovus incurred $29 million of acquisition related costs, excluding common share, preferred share and warrant issuance costs. These costs have been included in transaction costs in the Consolidated Statements of Earnings (Loss).

C) Liquidity and Commitments

Subsequent to the closing of the Arrangement on January 1, 2021, Cenovus obtained access to additional sources of liquidity including: $735 million in cash, $3.7 billion available on Husky’s committed credit facilities and $508 million available on Husky’s uncommitted demand facilities. Husky’s committed credit facilities have a capacity of $4.0 billion and its uncommitted demand facilities have a capacity of $975 million, of which $850 million may be drawn for general purposes, or the full amount can be available to issue letters of credit.

The Arrangement resulted in the assumption of Husky’s non-cancellable contracts and other commercial commitments. As at January 1, 2021, total commitments assumed by Cenovus were $18.7 billion, of which $7.4 billion were for various transportation and storage commitments. Transportation commitments include $1.7 billion that are subject to regulatory approval or have been approved but are not yet in service.

D) Segmented Disclosures

Management is in the process of finalizing the determination of the operating and reporting segments for the Company. It is anticipated that the Company’s business will be conducted predominately through an upstream and downstream segment. Management continues to evaluate how the segments may be presented and will make a final determination during the first quarter of 2021.

The upstream business is anticipated to be reported as follows:

 

  ●  

Oil Sands, includes the development and production of heavy oil and bitumen in northeast Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise and Tucker oil sands projects, as well as Lloydminster Thermal and Cold and Enhanced Oil Recovery assets.

 

  ●  

Conventional, includes the operations from conventional oil and natural gas production, including processing operations in the Deep Basin and other parts of Western Canada.

 

  ●  

Offshore, includes the offshore operations, exploration and development activities in the Asia Pacific region and Atlantic Canada region.

 

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The downstream business is anticipated to be reported as follows:

 

  ●  

Canadian Manufacturing, includes Cenovus’s owned and operated upgrader and asphalt refinery in Lloydminster, the owned and operated crude-by-rail terminal and two ethanol plants.

 

  ●  

Retail, includes the Canadian retail, commercial and wholesale channels.

 

  ●  

U.S. Manufacturing, includes the U.S. operations of wholly owned refineries in Lima and Superior, the jointly owned Wood River and Borger refineries with operator Phillips 66 and the jointly owned Toledo refinery with BP Products North America Inc. as operator.

 

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SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (1)

($ millions, except per share amounts)

           2020                 2019  
Revenues    Year     Q4     Q3     Q2     Q1     Year  
     

Gross Sales

             

Oil Sands

      7,514       2,227       2,195       1,065       2,027       10,838  

Conventional

      635       184       156       133       162       691  

Refining and Marketing

      6,051       1,345       1,569       1,088       2,049       10,513  

Corporate and Eliminations

      (609 )      (187 )      (108 )      (91 )      (223 )      (689 ) 

Less: Royalties

      364       143       153       21       47       1,173  

Total Revenues

      13,227       3,426       3,659       2,174       3,968       20,180  
           2020                 2019  
Operating Margin (2)    Year     Q4     Q3     Q2     Q1     Year  

Oil Sands

      1,113       616       638       125       (266 )      3,481  

Conventional

      196       82       30       32       52       242  
     1,309       698       668       157       (214 )      3,723  

Refining and Marketing

      (388 )      (73 )      (74 )      134       (375 )      737  

Total Operating Margin

      921       625       594       291       (589 )      4,460  
           2020                 2019  
Adjusted Funds Flow (3)    Year     Q4     Q3     Q2     Q1     Year  

Total Cash From (Used in) Operating Activities

      273       250       732       (834 )      125       3,285  

Deduct (Add Back):

             

Net Change in Other Assets and Liabilities

      (72 )      (14 )      (10 )      (9 )      (39 )      (84 ) 

Net Change in Non-Cash Working Capital (4)

     198       (77 )      328       (363 )      310       (333 ) 

Total Adjusted Funds Flow (4)

     147       341       414       (462 )      (146 )      3,702  

Total Per Share - Basic (4)

     0.12       0.28       0.34       (0.38 )      (0.12 )      3.01  

Total Per Share - Diluted (4)

     0.12       0.28       0.34       (0.38 )      (0.12 )      3.01  
           2020                 2019  
Earnings    Year     Q4     Q3     Q2     Q1     Year  

Total Operating Earnings (Loss) (5)

     (2,604 )      (551 )      (452 )      (414 )      (1,187 )      456  

Total Per Share - Diluted

      (2.12 )      (0.45 )      (0.37 )      (0.34 )      (0.97 )      0.37  
   

Total Net Earnings (Loss)

      (2,379 )      (153 )      (194 )      (235 )      (1,797 )      2,194  

Total Per Share - Basic and Diluted

      (1.94 )      (0.12 )      (0.16 )      (0.19 )      (1.46 )      1.78  
           2020                 2019  
Net Capital Investment (6)    Year     Q4     Q3     Q2     Q1     Year  

Oil Sands

               

Foster Creek

      193       36       32       36       89       243  

Christina Lake

      162       45       27       31       59       362  

Other Oil Sands

      72       9       6       11       46       51  

Total Oil Sands

      427       90       65       78       194       656  

Conventional

      78       39       12       11       16       103  

Refining and Marketing

      276       104       65       46       61       280  

Corporate

      60       9       6       12       33       137  

Total Capital Investment

      841       242       148       147       304       1,176  

Acquisitions

      18       8       4       -       6       13  

Divestitures

      (38 )      (36 )      (1 )      (1 )      -       (5 ) 

Net Acquisition and Divestiture Activity

      (20 )      (28 )      3       (1 )      6       8  

Net Capital Investment

      821       214       151       146       310       1,184  

 

LOGO

 

(1)

We renamed our Deep Basin segment to Conventional segment in the first quarter of 2020. For a description of our operations, refer to the Reportable Segments section of the Management’s Discussion and Analysis.

 

(2)

Operating Margin is an additional subtotal found in Note 1 of the Interim and Annual Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, inventory write-downs (reversals), 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.

 

(3)

Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as Cash From (Used in) Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable, inventory (excluding inventory write-downs and reversals), 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.

 

(4)

The comparative periods have been reclassified to conform with current period treatment of non-cash inventory write-downs (reversals).

 

(5)

Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain (loss), unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.

 

(6)

In the first quarter of 2020, our new resource play, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified.

 

(7)

Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.

 

124 |  CENOVUS ENERGY

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SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued) (1)

 

    

2020

     2019  
Financial Metrics (Non-GAAP Measures) (2)    Year      Q4     Q3     Q2     Q1     Year  

Net Debt to Adjusted EBITDA

      11.9x        11.9x       8.3x       6.0x       3.1x       1.6x  

Return on Capital Employed

      (8)%        (8)%       (7)%       (5)%       2%       10%  

Return on Common Equity

      (13)%        (13)%       (12)%       (10)%       2%       12%  
    

2020

    2019  
Income Tax & Exchange Rates    Year      Q4     Q3     Q2     Q1     Year  

Effective Tax Rates Using:

              

Net Earnings

      26.3%                (57.1)%  

Operating Earnings, Excluding Divestitures

      24.5%                39.8%  
     

Foreign Exchange Rates (US$ per C$1)

             

Average

      0.746        0.768       0.751       0.722       0.744       0.754  

Period End

      0.785        0.785       0.750       0.734       0.705       0.770  
    

2020

    2019  
Common Share Information    Year      Q4     Q3     Q2     Q1     Year  

Common Shares Outstanding (millions)

             

Period End

      1,228.9        1,228.9       1,228.9       1,228.9       1,228.9       1,228.8  

Average - Basic

      1,228.9        1,228.9       1,228.9       1,228.9       1,228.9       1,228.8  

Average - Diluted

      1,228.9        1,228.9       1,228.9       1,228.9       1,228.9       1,229.4  

Dividends ($ per share)

     0.0625        -       -       -       0.0625       0.2125  
   

Closing Price - TSX (C$ per share)

     7.75        7.75       5.19       6.35       2.84       13.20  

- NYSE (US$ per share)

     6.04        6.04       3.89       4.67       2.02       10.15  

Share Volume Traded (millions)

     5,644.5        1,419.0       854.4       1,831.6       1,539.5       2,711.7  

Operating Statistics - Before Royalties

              
    

2020

    2019  
Upstream Production Volumes    Year      Q4     Q3     Q2     Q1     Year  

Crude Oil and Natural Gas Liquids (bbls/d)

             

Oil Sands

              

Foster Creek

      163,210        158,068       164,954       166,032       163,820       159,598  

Christina Lake

      218,513        222,625       220,983       207,157       223,216       194,659  
     381,723        380,693       385,937       373,189       387,036       354,257  

Conventional

              

Crude Oil

      7,244        6,229       7,554       6,541       8,662       4,911  

Natural Gas Liquids (3)

     19,513        18,358       18,297       20,320       21,104       21,762  
       26,757        24,587       25,851       26,861       29,766       26,673  

Total Liquids Production

      408,480        405,280       411,788       400,050       416,802       380,930  
     

Natural Gas (MMcf/d)

             

Conventional (4)

     379        369       360       392       395       424  

Total Production (4)(5) (BOE per day)

      471,740        467,202       471,799       465,415       482,594       451,680  
    

2020

    2019  
Selected Average Benchmark Prices    Year      Q4     Q3     Q2     Q1     Year  

Crude Oil Prices (US$/bbl)

             

Brent

      43.21        45.24       43.37       33.27       50.96       64.18  

West Texas Intermediate (“WTI”)

      39.40        42.66       40.93       27.85       46.17       57.03  

Differential Brent - WTI

      3.81        2.58       2.44       5.42       4.79       7.15  

Western Canadian Select at Hardisty (“WCS”)

      26.80        33.36       31.84       16.38       25.64       44.27  

WCS (C$)

     35.59        43.41       42.41       22.42       34.11       58.77  

Differential WTI - WCS

      12.60        9.30       9.09       11.47       20.53       12.76  

Mixed Sweet Blend

      34.07        38.59       37.42       21.71       38.59       52.15  

Condensate (C5 @ Edmonton)

      37.16        42.54       37.55       22.30       46.28       52.86  

Differential WTI - Condensate (Premium)/Discount

      2.24        0.12       3.38       5.55       (0.11 )      4.17  

West Texas Sour (“WTS”)

      39.37        43.02       40.96       28.03       45.47       56.27  

Differential WTI - WTS

      0.03        (0.36 )      (0.03 )      (0.18 )      0.70       0.76  
     

Refining Margins 3-2-1 Crack Spreads (6) (US$/bbl)

             

Chicago

      7.54        7.05       7.89       6.44       8.79       16.00  

Group 3

      8.67        7.57       8.29       7.92       10.91       16.67  
     

Natural Gas Prices

              

AECO 7A Monthly Index (C$/Mcf) (7)

     2.24        2.77       2.15       1.91       2.14       1.62  

NYMEX (US$/Mcf)

     2.08        2.66       1.98       1.72       1.95       2.63  

Differential NYMEX - AECO (US$/Mcf)

     0.40        0.56       0.36       0.35       0.33       1.41  

 

LOGO

 

(1)

We renamed our Deep Basin segment to Conventional segment in the first quarter of 2020. For a description of our operations, refer to the Reportable Segments section of the Management’s Discussion and Analysis.

 

(2)   •    Net Debt includes the Company’s short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments.
  •    Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, revaluation gain, re-measurement gains (losses) on contingent payment, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve- month basis.
  •    Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders’ equity plus average debt.
  •    Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders’ equity.
(3)

Natural gas liquids include condensate volumes.

 

(4)

Includes production used for internal consumption by the Oil Sands segment of 344 MMcf per day and 336 MMcf per day for the three and twelve months ended December 31, 2020, respectively (336 MMcf per day and 320 MMcf per day for the three and twelve months ended December 31, 2019, respectively).

 

(5)

Natural gas volumes have been converted to barrels of oil equivalent (“BOE”) on the basis of six thousand cubic feet (“Mcf”) to one barrel (“bbl”). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

 

(6)

The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based crude oil feedstock prices and on a last in, first out accounting basis (“LIFO”).

 

(7)

Alberta Energy Company (“AECO”) natural gas monthly index.

 

2020 ANNUAL REPORT  | 125

Table of Contents

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued) (1)

 

    

2020

    2019  
Effective Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)    Year      Q4     Q3     Q2     Q1     Year  

Oil Sands (2)

             

Foster Creek

      7.9%        5.9 %      7.4 %      16.0 %      11.7 %      18.8 % 

Christina Lake

      14.4%        16.6 %      13.4 %      18.0 %      9.5 %      21.6 % 
     

Conventional

              

Crude Oil

      11.6%        9.2 %      10.9 %      14.2 %      13.0 %      16.3 % 

Natural Gas Liquids

      12.2%        21.9 %      38.3 %      (9.2 )%      (4.9 )%      3.9 % 

Natural Gas

      4.8%        2.1 %      13.5 %      2.5 %      1.5 %      1.1 % 

Netbacks

Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less royalties, transportation and blending, and operating expenses divided by sales volumes. Netbacks do not reflect the non-cash write-downs or reversals of product inventory until the product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual Management’s Discussion and Analysis.

The Oil Sands and Conventional netbacks are calculated on a gross basis and exclude adjustments for the natural gas that is produced by the Conventional segment and used as fuel by the Oil Sands segment. The consolidated netback is calculated on a net basis, after adjustments for natural gas produced by the Conventional segment and used as fuel by the Oil Sands segment.

 

    

2020

    2019  
Oil Sands Netbacks (Excluding Realized Gain (Loss) on Risk Management)    Year     Q4     Q3     Q2     Q1     Year  

Heavy Oil - Foster Creek (3) ($/bbl)

            

Sales Price

      30.80       41.52       41.51       14.28       27.05       57.21  

Royalties

      1.57       1.89       2.44       0.56       1.47       8.44  

Transportation and Blending

      11.05       9.74       8.59       11.32       14.37       11.70  

Operating

      9.24       10.34       9.04       8.33       9.28       9.14  

Netback

      8.94       19.55       21.44       (5.93 )      1.93       27.93  

Heavy Oil - Christina Lake (3) ($/bbl)

            

Sales Price

      27.04       37.20       38.44       11.22       18.87       50.91  

Royalties

      2.90       5.07       4.27       1.00       1.01       9.42  

Transportation and Blending

      6.95       6.55       6.78       6.19       8.18       6.64  

Operating

      6.79       7.50       6.53       6.52       6.62       7.33  

Netback

      10.40       18.08       20.86       (2.49 )      3.06       27.52  

Total Heavy Oil - Oil Sands (3) ($/bbl)

            

Sales Price

      28.64       39.02       39.67       12.64       22.35       53.78  

Royalties

      2.34       3.73       3.54       0.80       1.21       8.97  

Transportation and Blending

      8.70       7.90       7.51       8.56       10.81       8.94  

Operating

      7.84       8.70       7.53       7.36       7.75       8.15  

Netback

      9.76       18.69       21.09       (4.08 )      2.58       27.72  
    

2020

    2019  

Conventional Netbacks (Excluding Realized Gain (Loss) on Risk Management)

     Year       Q4       Q3       Q2       Q1       Year  

Total Conventional (3)(4) ($/BOE)

            

Sales Price

      17.84       21.63       18.28       14.48       17.23       17.95  

Royalties

      1.23       1.65       2.95       0.12       0.35       0.83  

Transportation and Blending

      2.46       2.28       2.62       2.38       2.55       2.31  

Operating

      8.99       8.34       9.55       9.05       9.01       8.79  

Netback

      5.16       9.36       3.16       2.93       5.32       6.02  
    

2020

    2019  

Operations Netbacks (Excluding Realized Gain (Loss) on Risk Management)

     Year       Q4       Q3       Q2       Q1       Year  

Total Operations (3)(4) ($/BOE)

            

Sales Price

      28.23       38.37       38.55       13.04       22.47       50.63  

Royalties

      2.41       3.81       3.86       0.75       1.17       8.23  

Transportation and Blending

      8.52       7.82       7.46       8.33       10.43       8.51  

Operating

      7.21       7.41       7.09       7.00       7.33       7.87  

Netback

      10.09       19.33       20.14       (3.04 )      3.54       26.02  
    

2020

    2019  

Realized Gain (Loss) on Risk Management

      Year       Q4       Q3       Q2       Q1       Year  

Sales (4) ($/BOE)

     (1.74 )      (1.05 )      (3.46 )      (1.81 )      (0.63 )      (0.16 ) 
    

2020

                            2019  

Refinery Operations (5)

     Year       Q4       Q3       Q2       Q1       Year  

Crude Oil Capacity (Mbbls/d)

     495       495       495       495       495       482  

Crude Oil Runs (Mbbls/d)

     372       338       382       325       442       443  

Heavy Oil

      149       133       154       112       197       177  

Light/Medium

      223       205       228       213       245       266  

Crude Utilization

      75%       68%       77%       66%       89%       92%  

Refined Products (Mbbls/d)

     385       350       397       332       460       466  

 

(1)

We renamed our Deep Basin segment to Conventional segment in the first quarter of 2020. For a description of our operations, refer to the Reportable Segments section of the Management’s Discussion and Analysis.

 

(2)

Q4 effective royalty rate for Christina Lake and Foster Creek reflects the annual weighted average unit price adjustments and audit adjustments related to prior periods. The Q4 effective royalty rate, before the adjustments would be 14.4% and 6.8% for Christina Lake and Foster Creek, respectively.

 

(3)

Netbacks do not reflect the non-cash write-downs or reversals of product inventory until the product is sold. There was no impact to netbacks for total operations from realizing inventory write-downs for the three months ended December 31, 2020.

 

(4)

Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

 

(5)

Represents 100 percent of the Wood River and Borger refinery operations.

 

126 |  CENOVUS ENERGY

Table of Contents

ADVISORY

Oil and Gas Information

The estimates of Cenovus’s reserves were prepared effective December 31, 2020 by IQREs, based on the COGE Handbook and in compliance with the requirements of NI 51-101. Estimates are presented using the IQRE Average forecast prices and costs dated January 1, 2021 price forecasts. For additional information about our reserves and other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended December 31, 2020.

Total proved reserves and total proved plus probable reserves for Cenovus and Husky are based on a simple summation of reserves prepared independently for each company. Cenovus has not constructed a consolidated reserves report of the combined assets of Cenovus and Husky and has not engaged an independent reserves evaluator to produce such a report in accordance with NI 51-101. Reserves calculated for the combined company could be materially different than reserves calculated by adding the reserves of the two companies. The anticipated increase in reserves for the combined company may be more or less than anticipated, and the difference could be material.

Cenovus and Husky employed different methodologies to estimate their reserves information for the year ended December 31, 2020. All of Husky’s oil and gas reserves estimates were prepared by internal qualified reserves evaluators using a formalized process for determining, approving and booking reserves. As a result, the actual reserves of Cenovus (after giving effect to the Arrangement), if calculated as of December 31, 2020 by an independent reserves evaluator in accordance with NI 51-101, may differ from the anticipated total proved reserves and total proved plus probable reserves of the combined company for a number of reasons, and such differences may be material. Barrels of Oil Equivalent – natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

Forward-looking Information

This document contains certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking information”) within the meaning of applicable securities legislation, including the U.S. Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward-looking information in this document is identified by words such as “achieve”, “aim”, “anticipate”, “believe”, “can be”, “capacity”, “committed”, “commitment”, “continue”, “could”, “deliver”, “drive”, “enhance”, “ensure”, “estimate”, “expect”, “focus”, “forecast”, “forward”, “future”, “guidance”, “maintain”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “priority”, “re-establishing”, “strategy”, “should”, “target”, “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: strategy and related milestones; schedules and plans; stronger financial performance in 2021; anticipated benefits of the Arrangement, including: achieving $1.2 billion of incremental annual free funds flow comprised of approximately $600 million in annual corporate and operating synergies and approximately $600 million in annual sustaining capital allocation synergies independent of commodity prices with the majority of annual savings achieved within the first year of combined operations and the full amount achieved within year two, the impact of the Arrangement on certain reserves data and other oil and gas information, including any pro forma information, the planned amalgamation of Cenovus and Husky, achieving longer term cost savings and margin enhancements based on further physical integration, reducing our exposure to Alberta heavy oil price differentials while maintaining exposure to global commodity prices, reducing condensate costs associated with heavy oil transportation over the longer term, accelerating balance sheet deleveraging, achieving sustainable growth in shareholder distributions; improving efficiencies to drive incremental capital, operating and G&A cost reductions; the ability of our assets to respond to market signals and ramp up production accordingly; statements and expectations relating to our 2021 budget; our ability to partially mitigate the impact of crude oil and refined product differentials through transportation commitments, integration, marketing agreements, dynamic storage, traditional storage tanks and financial hedge contracts; maintaining an investment grade credit rating; reduced free funds flow volatility; enhanced resilience; financial flexibility to withstand economic volatility; improved capacity to generate significant free funds flow; achieving Net Debt to Adjusted EBITDA target of less than 2.0 times without the need for asset dispositions; our focus on allocating free funds flow to reduce Net Debt to less than $10 billion and targeting a longer-term Net Debt level at or below $8 billion; focus on maximizing shareholder value through disciplined, returns-focused capital investment and cost leadership to realize the best margins for our products and environmental benefits; maintaining liquidity, delivering a stable cash flow through price cycles and preserving a

 

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resilient balance sheet by reducing spending while maintaining safe and reliable operations; the expected production levels of our business segments in 2021; longer-term focus on sustainably growing shareholder returns and reducing Net Debt as well as continuing to integrate ESG considerations into our business plan; maintaining a strong balance sheet to help Cenovus navigate through commodity price volatility; evaluating disciplined investment in our portfolio against dividends, share repurchases and achieving and maintaining the optimal debt level while targeting investment grade status; focusing investment on areas where we believe we have the greatest competitive advantage; plan to achieve our strategy by leveraging our strategic focus areas including our oil sands, conventional oil and natural gas assets, marketing, transportation and refining portfolio, and our people; our 2021 capital investment plan, operating cost reductions and G&A reductions enhances our financial resilience and financial capability to maintain our base business, deliver safe and reliable operations and to continue to challenge our cost structure in the face of these unprecedented conditions; our ability to reduce spending in response to commodity prices and other economic factors in order to maintain our financial resilience; ample liquidity and runway to sustain operations through a prolonged market downturn; anticipated volatility of demand and crude oil prices through 2021 as a result of continued uncertainty around COVID-19, with crude oil and refined products demand and recovery dependent on the success of economic relaunches and the overall supply and demand balance; maintaining a high level of capital discipline and managing our capital structure to help ensure the Company has sufficient liquidity through all stages of the economic cycle; demand for refined product being an early indicator of recovery from the impact of COVID-19; increases in staff levels at sites and offices will continue to be achieved in accordance with guidance received from the applicable federal, provincial, state and local governments and public health officials; expected recovery of the price of and demand for crude oil and refined products over the longer term as COVID-19 vaccines are administered and economies re-open from the impacts of the pandemic; expected timing for oil sands expansion phases projections for 2021 and future years and our plans and strategies to realize such projections; the reduction of transportation costs caused by the temporary suspension of the crude-by-rail program; reaching a broader customer base; forecast exchange rates and trends; future opportunities for oil and natural gas development; forecast operating and financial results, including forecast sales prices, costs and cash flows; our ability to satisfy payment obligations as they become due; priorities for and approach to capital investment decisions or capital allocation, including decisions pertaining to new projects and phases; planned capital expenditures, including the amount, timing and funding sources thereof; all statements with respect to our 2021 guidance estimates; expected future production, including the timing, stability or growth thereof; our ability to manage our production well rates in response to pipeline capacity constraints, storage constraints and crude oil price differentials; our ability to take steps to partially mitigate against wider WTI and WCS price differentials; our expectation that the general outlook for light crude oil prices will be tied primarily to the supply and demand response to the current uncertain price environment, the impact of oversupply, and global demand impacts amid COVID-19 concerns; our expectation that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply cuts are sustainable, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the Trans Mountain Expansion project, and the level of crude-by-rail activity; our expectation that in 2021 refining market crack spreads will remain weak relative to previous years as a result of significantly reduced refined products demand due to COVID-19; our expectation that our capital investment and near-term cash requirements will be funded through cash from operating activities and prudent use of our balance sheet capacity including draws on our credit and demand facilities, management of our asset portfolio and other corporate and financial opportunities that may be available to us; statements about our debt level as we manage through the low commodity price environment; expected reserves; focus on mid-term strategies to broaden market access for our crude oil production; supporting proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil; impact on alignment of transportation and storage commitments and production growth; all statements related to government royalty regimes applicable to Cenovus, which regimes are subject to change; our ability to preserve our financial resilience and various plans and strategies with respect thereto; our priorities, including for 2021; future impact of regulatory measures; forecast commodity prices, differentials and trends and expected impact; potential impacts of various risks, including those related to commodity prices and climate change; the potential effectiveness of our risk management strategies; new accounting standards, the timing for the adoption thereof, and anticipated impact on the Consolidated Financial Statements; our expectation that any liabilities that may arise out of legal claims associated with the normal course of our operations are not likely to have a material effect on our Consolidated Financial Statements; the availability and repayment of our credit facilities; potential asset sales; expected impacts of the contingent payment to ConocoPhillips; development of a new five-year business plan for the combined company in 2021; being a leader in ESG performance; statements about new ESG targets and ambitions, plans to achieve them and our commitment to transparent performance reporting; achieving net zero emissions by 2050; holding engagement sessions with shareholders; future investment, use and development of technology and equipment and associated future outcomes; our ability to access and implement all technology necessary to efficiently and effectively operate our assets and achieve expected future results; planned capital expenditures; and projected growth and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

Statements relating to “reserves” are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicated or estimated, and can be profitably produced in the future.

 

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Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which our forward-looking information is based include, but are not limited to: forecast oil and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials; our ability to realize the benefits and anticipated cost synergies associated with the combination of Cenovus and Husky; Cenovus’s ability to successfully integrate the business of Husky, including new business activities, assets, operating areas, regulatory jurisdictions, personnel and business partners for Cenovus; the accuracy of any assessments undertaken in connection with the Husky Arrangement and any resulting pro forma information; our forecast production volumes are subject to potential further ramp down of production based on business and market conditions; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to legislation and regulations, Indigenous relations, interest rates, foreign exchange rates, competitive conditions and the supply and demand for crude oil and natural gas, NGLs, condensate and refined products; the political, economic and social stability of jurisdictions in which Cenovus operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, civil unrest or other similar events; the prevailing climatic conditions in Cenovus’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to our share price and market capitalization over the long term; opportunities to repurchase shares for cancellation at prices acceptable to us; cash flows, cash balances on hand and access to credit and demand facilities being sufficient to fund capital investments; foreign exchange rate risk, including with respect to our US$ debt and refining capital and operating expenses; our ability to reduce our 2021 oil sands production, including without negative impacts to our assets; realization of expected capacity to store within our oil sands reservoirs barrels not yet produced, including that we will be able to time production and sales of our inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to the extent to which voluntary economically driven supply cuts are made, the potential start-up of the Enbridge Inc.’s Line 3 Replacement Program, the completion of Trans Mountain Expansion project, and the level of crude-by-rail activity; the ability of our refining capacity, dynamic storage, existing pipeline commitments and financial hedge transactions to partially mitigate a portion of our WCS crude oil volumes against wider differentials; production declines from both associated gas and dry gas, along with rebounding U.S. demand and liquified natural gas exports should tighten North American gas fundamentals further in 2021 and result in stronger prices than 2020 on an annual basis; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; future use and development of technology and associated expected future results; our ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; the sufficiency of existing cash balances, internally generated cash flows, existing credit facilities, management of the Corporation’s asset portfolio and access to capital markets to fund future development costs and dividends, including any increase thereto; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to access sufficient capital to pursue our development plans; our ability to complete asset sales, including with desired transaction metrics and within the timelines we expect; the stability of general domestic and global economic, market and business conditions; forecast inflation and other assumptions inherent in Cenovus’s 2021 guidance available on cenovus.com and as set out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the contingent payment to ConocoPhillips; our ability to access and implement all technology and equipment necessary to achieve expected future results and that such results are realized; our ability to implement capital projects or stages thereof in a successful and timely manner; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

2021 guidance, as updated January 28, 2021 and available on cenovus.com, assumes: Brent prices of US$49.50/bbl, WTI prices of US$46.50/bbl; WCS of US$32.50/bbl; Differential WTI-WCS of US$14.00/bbl; AECO natural gas prices of $2.50/Mcf; Chicago 3-2-1 crack spread of US$11.00/bbl; and an exchange rate of $0.78 US$/C$.

The risk factors and uncertainties that could cause our actual results to differ materially from the forward-looking information, include, but are not limited to: the effect of the COVID-19 pandemic on our business, including any related restrictions, containment, and treatment measures taken by varying levels of government in the jurisdictions in which we operate; the success of our new COVID-19 workplace policies and the return of our people to our workplace; our ability to achieve the benefits and anticipated cost synergies anticipated with the Arrangement in a timely manner or at all; the ability of Cenovus and Husky to amalgamate; Cenovus’s ability to successfully integrate Husky’s business with its own in a timely and cost effective manner or at all; the effects of entering new business activities; unforeseen or undisclosed liabilities associate with the Arrangement; the inaccuracy of any assessments undertaken in connection with the Arrangement and any resulting pro forma information; the inaccuracy of any information provided by Husky; our ability to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; the effect of Cenovus’s increased indebtedness; the effect of new significant shareholder; volatility of and other assumptions regarding commodity prices; the duration of the market downturn; foreign exchange risk, including related to agreements denominated in foreign currencies; our continued liquidity is sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential in Alberta does not remain largely tied to the extent to which voluntary economically driven

 

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supply cuts are made, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the Trans Mountain Expansion project, and the level of crude-by-rail activity; our ability to achieve lower transportation costs as a result of temporarily suspending the crude-by-rail program; our ability to realize the expected impacts of our capacity to store within our oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of our risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; the accuracy of our share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; our ability to maintain desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; changes to our dividend plans; our ability to utilize tax losses in the future; the accuracy of our reserves, future production and future net revenue estimates; the accuracy of our accounting estimates and judgements; our ability to replace and expand oil and gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of our assets or goodwill from time to time; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated operations and business; reliability of our assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events resulting in operational interruptions, including blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics or pandemics, and catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, iceberg incidents, acts of vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and increased insurance deductibles or premiums; the cost and availability of equipment necessary to our operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and Cenovus’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to our business, including potential cyberattacks; geo-political and other risks associated with our international operations; risks associated with climate change and our assumptions relating thereto; the timing and the costs of well and pipeline construction; our ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and our ability to attract and retain, critical talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which we operate or to any of the infrastructure upon which we rely; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which we operate or supply; the status of our relationships with the communities in which we operate, including with Indigenous communicates; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against us.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of our material risk factors, see Risk Management and Risk Factors in this MD&A, and to the risk factors described in other documents Cenovus files from time to time with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Corporation’s website at cenovus.com. Additional information concerning Husky’s business and assets as of December 31, 2020 may be found in the Husky AIF and this MD&A, each of which is filed and available on SEDAR under Husky’s profile at sedar.com.

 

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Information on or connected to Cenovus’s at website cenovus.com or Husky’s website at huskyenergy.com does not form part of this MD&A unless expressly incorporated by reference herein.

ABBREVIATIONS

The following abbreviations have been used in this document:

 

Crude Oil    Natural Gas

bbl

    barrel    Mcf    thousand cubic feet

Mbbls/d

    thousand barrels per day    MMcf    million cubic feet

MMbbls

    million barrels    Bcf    billion cubic feet

BOE

    barrel of oil equivalent    MMBtu    million British thermal units

MMBOE

    million barrel of oil equivalent    GJ    gigajoule

WTI

    West Texas Intermediate    AECO    Alberta Energy Company

WCS

    Western Canadian Select    NYMEX    New York Mercantile Exchange

CDB

    Christina Dilbit Blend      

MSW

    Mixed Sweet Blend      

WTS

    West Texas Sour      

DEFINITIONS

Scope 1 emissions are direct emissions from owned or operated facilities. Cenovus accounts for emissions on a gross operatorship basis. This includes fuel combustion, venting, flaring and fugitive emissions. It does not include emissions from the 50 percent non-operated ownership in the Company’s refineries or emissions from non-operated Conventional assets.

Scope 2 emissions are indirect emissions from the generation of purchased energy for the Company’s operated facilities. For Cenovus, this is limited to electricity imports.

 

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NETBACK RECONCILIATIONS

The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Consolidated Financial Statements.

Total Production

Upstream Financial Results

 

     Per Consolidated Financial Statements    Adjustments          Basis of
Netback
Calculation		  

Year Ended

December 31, 2020 ($ millions)

     
 Oil
Sands (1)		  
 		          Conventional (1) (2)           
 Total
Upstream		  
 		          Condensate            Inventory           
 Internal
Usage (3)		  
 		          Other           
 Total
Upstream		  
 

Gross Sales

      7,514          635          8,149          (3,452 )         -          (295 )         (58 )         4,344  

Royalties

      324          40          364          -          6          -          -          370  

Transportation and Blending

      4,399          81          4,480          (3,452 )         285          -          -          1,313  

Operating

      1,094          318          1,412          -          25          (295 )         (33 )         1,109  

Inventory Write-Down (Reversal)

      316          -          316                     (316 )                               -  

Netback

      1,381          196          1,577          -          -          -          (25 )         1,552  

(Gain) Loss on Risk Management

      268          -          268          -          -          -          -          268  

Operating Margin

      1,113          196          1,309          -          -          -          (25 )         1,284  
                                                                                     

 

     Per Consolidated Financial Statements    Adjustments          Basis of
Netback
Calculation		  

Year Ended

December 31, 2019 ($ millions)

     
 Oil
Sands (1)		  
 		          Conventional (1) (2)           
 Total
Upstream		  
 		          Condensate            Inventory           
 Internal
Usage (3)		  
 		          Other           
 Total
Upstream		  
 

Gross Sales

      10,838          691          11,529          (4,021 )         -          (222 )         (64 )         7,222  

Royalties

      1,143          30          1,173          -          -          -          1          1,174  

Transportation and Blending

      5,152          82          5,234          (4,021 )         -          -          1          1,214  

Operating

      1,039          337          1,376          -          -          (222 )         (33 )         1,121  

Netback

      3,504          242          3,746          -          -          -          (33 )         3,713  

(Gain) Loss on Risk Management

      23          -          23          -          -          -          -          23  

Operating Margin

      3,481          242          3,723          -          -          -          (33 )         3,690  
                                                                                     

 

     Per Consolidated Financial Statements    Adjustments            Basis of
Netback
Calculation		  

Year Ended

December 31, 2018 ($ millions) (4)

    
 Oil
Sands(1)		  
 		          Conventional(1) (2)           
 Continuing
Operations		  
 		          Condensate            Inventory           
 Internal
Usage(3)		  
 		          Other               
 Continuing
Operations		  
 

Gross Sales

      10,026          904          10,930          (4,993 )         -          (179 )         (69 )         5,689  

Royalties

      473          73          546          -          -          -          -          546  

Transportation and Blending

      5,879          90          5,969          (4,993 )         -          -          (4 )         972  

Operating

      1,037          403          1,440          -          -          (179 )         (37 )         1,224  

Netback

      2,637          338          2,975          -          -          -          (28 )         2,947  

(Gain) Loss on Risk Management

      1,551          26          1,577          -          -          -          -          1,577  

Operating Margin

      1,086          312          1,398          -          -          -          (28 )         1,370  
                                                                                     

 

(1)

Found in Note 1 of the Consolidated Financial Statements.

(2)

This segment was previously referred to as the Deep Basin segment.

(3)

Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.

(4)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

 

     Per Interim Consolidated Financial Statements          Adjustments          Basis of
Netback
Calculation		  

Three Months Ended

December 31, 2020 ($ millions)

     
 Oil
Sands (5)		  
 		          Conventional (5) (6)           
 Total
Upstream		  
 		          Condensate            Inventory           
 Internal
Usage (7)		  
 		          Other           
 Total
Upstream		  
 

Gross Sales

      2,227          184          2,411          (853 )         -          (92 )         (17 )         1,449  

Royalties

      131          12          143          -          -          -          -          143  

Transportation and Blending

      1,131          18          1,149          (853 )         -          -          -          296  

Operating

      309          72          381          -          -          (92 )         (10 )         279  

Inventory Write-Down (Reversal)

      -          -          -          -          -          -          -          -  

Netback

      656          82          738          -          -          -          (7 )         731  

(Gain) Loss on Risk Management

      40          -          40          -          -          -          -          40  

Operating Margin

      616          82          698          -          -          -          (7 )         691  
                                                                                     

 

(5)

Found in Note 1 of the interim Consolidated Financial Statements.

(6)

This segment was previously referred to as the Deep Basin segment.

(7)

Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.

 

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     Per Interim Consolidated Financial Statements          Adjustments         

 Basis of   

Netback   

Calculation   

  

 

 

Three Months Ended

December 31, 2019 ($ millions)

     

 Oil   

Sands (1)   

  

 

          Conventional (1) (2)             

 Total   

Upstream   

  

 

          Condensate               Inventory           

Internal   

Usage (3)   

          Other              

 Total   

Upstream   

  

 

Gross Sales

      2,659             190            2,849             (1,060)            -          (82)          (13)            1,694     

Royalties

      316             9            325             -             -          -           1             326     

Transportation and Blending

      1,416             20            1,436             (1,060)            -          -           1             377     

Operating

      268             80            348             -             -          (82)          (6)            260     

Netback

      659             81            740             -             -          -           (9)            731     

(Gain) Loss on Risk Management

      (15)            -            (15)            -             -          -           -             (15)    

Operating Margin

      674             81            755             -             -          -           (9)            746     
                                                                                 

 

(1)

Found in Note 1 of the interim Consolidated Financial Statements.

(2)

This segment was previously referred to as the Deep Basin segment.

(3)

Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.

Oil Sands

 

     Basis of Netback Calculation          Adjustments         



 Per  

Consolidated  
Financial  
Statements (4)  

  

 
 
 

Year Ended

December 31, 2020 ($ millions)

     

 Foster  

Creek  

  

 

          Christina Lake             

 Total  

Crude Oil  

  

 

         

 Natural  

Gas  

  

 

          Condensate              Inventory               Other              

 Total  

Oil Sands  

  

 

Gross Sales

      1,859            2,194            4,053            -            3,452            -             9             7,514    

Royalties

      95            235            330            -            -            (6)            -             324    

Transportation and Blending

      667            565            1,232            -            3,452            (285)            -             4,399    

Operating

      558            551            1,109            -            -            (25)            10             1,094    

Inventory Write-Down (Reversal)

      -            -            -                                    316                          316    

Netback

      539            843            1,382            -            -            -             (1)            1,381    

(Gain) Loss on Risk Management

      111            157            268            -            -            -             -             268    

Operating Margin

      428            686            1,114            -            -            -             (1)            1,113    
                                                                                     

 

     Basis of Netback Calculation          Adjustments         



 Per  

Consolidated  
Financial  
Statements (4)  

  

 
 
 

Year Ended

December 31, 2019 ($ millions)

     

 Foster  

Creek  

  

 

          Christina Lake             

 Total  

Crude Oil  

  

 

         

 Natural  

Gas  

  

 

              Condensate              Inventory              Other                  

 Total  

Oil Sands  

  

 

Gross Sales

      3,295            3,511            6,806            -            4,021            -            11             10,838    

Royalties

      486            650            1,136            -            -            -            7             1,143    

Transportation and Blending

      674            458            1,132            -            4,021            -            (1)            5,152    

Operating

      526            505            1,031            -            -            -            8             1,039    

Netback

      1,609            1,898            3,507            -            -            -            (3)            3,504    

(Gain) Loss on Risk Management

      10            13            23            -            -            -            -             23    

Operating Margin

      1,599            1,885            3,484            -            -            -            (3)            3,481    
                                                                                     
     Basis of Netback Calculation          Adjustments         


 Per  
Consolidated  
Financial  
Statements  (4)  		  
 
 
 

Year Ended

December 31, 2018 ($ millions) (5)

    

 Foster  

Creek  

  

 

          Christina Lake             

 Total  

Crude Oil  

  

 

         

 Natural   

Gas   

  

 

              Condensate              Inventory              Other                 

 Total  

Oil Sands  

  

 

Gross Sales

      2,531            2,489            5,020            1             4,993            -            12            10,026    

Royalties

      371            102            473            -             -            -            -            473    

Transportation and Blending

      495            391            886            -             4,993            -            -            5,879    

Operating

      532            492            1,024            2             -            -            11            1,037    

Netback

      1,133            1,504            2,637            (1)            -            -            1            2,637    

(Gain) Loss on Risk Management

      683            868            1,551            -             -            -            -            1,551    

Operating Margin

      450            636            1,086            (1)            -            -            1            1,086    
                                                                                     

 

(4)

Found in Note 1 of the Consolidated Financial Statements.

(5)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

 

    
 Basis of Netback Calculation
 
        Adjustments         



 Per Interim  

Consolidated  
Financial  
Statements (1)  

  

 
 
 

Three Months Ended

December 31, 2020 ($ millions)

     

 Foster  

Creek  

  

 

         

 Christina  

Lake  

  

 

         

 Total  

Crude Oil  

  

 

         

 Natural  

Gas  

  

 

          Condensate              Inventory              Other             

 Total  

Oil Sands  

  

 

Gross Sales

      615            756            1,371            -            853            -            3            2,227    

Royalties

      28            103            131            -            -            -            -            131    

Transportation and Blending

      144            134            278            -            853            -            -            1,131    

Operating

      154            152            306            -            -            -            3            309    

Inventory Write-Down (Reversal)

      -            -            -            -            -            -            -            -    

Netback

      289            367            656            -            -            -            -            656    

(Gain) Loss on Risk Management

      15            25            40            -            -            -            -            40    

Operating Margin

      274            342            616            -            -            -            -            616    
                                                                                     

 

(1)

Found in Note 1 of the interim Consolidated Financial Statements.

 

2020 ANNUAL REPORT  | 133

Table of Contents
     Basis of Netback Calculation          Adjustments         


 Per Interim
Consolidated
Financial
Statements (1)		  
 
 
 

Three Months Ended

December 31, 2019 ($ millions)

     

 Foster   

Creek   

  

 

         

 Christina   

Lake   

  

 

         

 Total   

Crude Oil   

  

 

         

 Natural  

Gas  

  

 

          Condensate              Inventory              Other              
 Total Oil
Sands		  
 

Gross Sales

      731             866             1,597             -            1,060          -            2             2,659     

Royalties

      130             179             309             -            -            -            7             316     

Transportation and Blending

      207             150             357             -            1,060            -            (1)            1,416     

Operating

      132             136             268             -            -            -            -             268     

Netback

      262             401             663             -            -            -            (4)            659     

(Gain) Loss on Risk Management

      (5)            (10)            (15)            -            -            -            -             (15)    

Operating Margin

      267             411             678             -            -            -            (4)            674     
                                                                                     

 

(1)

Found in Note 1 of the interim Consolidated Financial Statements.

Conventional (2)

 

    

 Basis of Netback  

Calculation  

  

 

        Adjustments           


 Per Consolidated  

Financial  
Statements(3)  

  

 
 

Year Ended

December 31, 2020 ($ millions)

      Total            Other(4)              

 Total  

Conventional  

  

 

Gross Sales

      586            49            635    

Royalties

      40            -            40    

Transportation and Blending

      81            -            81    

Operating

      295            23            318    

Netback

      170            26            196    

(Gain) Loss on Risk Management

      -            -            -    

Operating Margin

      170            26            196    
                              
    

 Basis of Netback  

Calculation  

  

 

        Adjustments           

 Per Consolidated  

Financial  

Statements(3)  

  

 

 

Year Ended

December 31, 2019 ($ millions)

      Total              Other(4)              

 Total  

Conventional  

  

 

Gross Sales

      638            53            691    

Royalties

      30            -            30    

Transportation and Blending

      82            -            82    

Operating

      312            25            337    

Netback

      214            28            242    

(Gain) Loss on Risk Management

      -            -            -    

Operating Margin

      214            28            242    
                              
    

 Basis of Netback  

Calculation  

  

 

        Adjustments           

 Per Consolidated  

Financial  

Statements(3)  

  

 

 

Year Ended

December 31, 2018 ($ millions) (5)

     Total              Other(4)              

 Total  

Conventional  

  

 

Gross Sales

      847            57            904    

Royalties

      73            -            73    

Transportation and Blending

      86            4            90    

Operating

      377            26            403    

Netback

      311            27            338    

Operating Margin

      285            27            312    
                              

 

(2)

This segment was previously referred to as the Deep Basin segment.

(3)

Found in Note 1 of the Consolidated Financial Statements.

(4)

Reflects operating margin from processing facility.

(5)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated.

 

134 |  CENOVUS ENERGY

Table of Contents
  

Basis of Netback  

Calculation  

      Adjustments     

Per Interim  

Consolidated  

Financial  

Statements(1)  

Three Months Ended

December 31, 2020 ($ millions)

    Total          Other(2)          

Total

Conventional

Gross Sales

    170        14        184  

Royalties

    12        -        12  

Transportation and Blending

    18        -        18  

Operating

    65        7        72  

Netback

    75        7        82  

(Gain) Loss on Risk Management

    -        -        -  

Operating Margin

    75        7        82  
                  

   

Basis of Net back  

Calculation  

      Adjustments     

Per Interim  

Consolidated  

Financial  

Statements(1)  

Three Months Ended

December 31, 2019 ($ millions)

    Total        Other(2)          

Total  

Conventional  

Gross Sales

    179        11        190  

Royalties

    9        -        9  

Transportation and Blending

    20        -        20  

Operating

    74        6        80  

Netback

    76        5        81  

(Gain) Loss on Risk Management

    -        -        -  

Operating Margin

    76        5        81  
                  

 

(1)

Found in Note 1 of the interim Consolidated Financial Statements.

(2)

Reflects operating margin from processing facility.

The following table provides the sales volumes used to calculate Netback.

Sales Volumes

 

        

Three Months Ended

        Year Ended December 31
(barrels per day, unless otherwise stated)         December 31,  
2020  		         December 31,  
2019  		         2020           2019           2018  

Oil Sands

                         

Foster Creek

     

161,108  

      153,797        164,906        157,770        162,685  

Christina Lake

     

220,676  

     

207,399  

     

221,675  

     

188,910  

     

204,016  

Total Oil Sands Crude Oil

     

381,784  

     

361,196  

     

386,581  

     

346,680  

     

366,701  

Conventional (3)

                        

Total Liquids

     

24,543  

     

26,197  

     

26,646  

     

26,673  

     

32,454  

Natural Gas (MMcf per day)

     

369  

     

403  

     

379  

     

424  

     

527  

Total Conventional (BOE per day)

     

86,123  

      93,317        89,821       

97,423  

     

120,258  

Less: Internal Consumption (4) (MMcf per day)

     

(344)

     

(336)

     

(336)

     

(320)

     

(306)

Sales From Continuing Operations (4) (BOE per day)

     

410,864  

      398,457        420,456       

390,813  

     

436,163  

                                  

 

(3)

This segment was previously referred to as the Deep Basin segment.

(4)

Less natural gas volumes used for internal consumption by the Oil Sands segment

 

2020 ANNUAL REPORT  | 135

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NOTES

 

136 |  CENOVUS ENERGY

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NOTES

 

2020 ANNUAL REPORT  | 137

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138 |  CENOVUS ENERGY

Table of Contents

NOTES

 

2020 ANNUAL REPORT  | 139

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140 |  CENOVUS ENERGY

Table of Contents
         
 

I N F O R M A T I O N  F O R

 

SHAREHOLDERS

        
 

ANNUAL MEETING

Due to the COVID-19 pandemic, Cenovus will hold its Annual Meeting of Shareholders in a virtual format again this year to help mitigate health and safety risks to our community, shareholders, employees and other stakeholders. Holders of Cenovus common shares are invited to attend the virtual Annual Meeting of Shareholders to be held on Wednesday, May 12, 2021 at 1 p.m. MT via live webcast accessible online at https://web.lumiagm.com/445299876. Please see our Management Information Circular available on cenovus.com for additional information.

 

TRANSFER AGENT & REGISTRAR

Computershare Investor Services Inc.

8th Floor, 100 University Avenue

Toronto, Ontario M5J 2Y1 Canada

www.investorcentre.com/cenovus

Shareholder inquiries by phone:

North America 1.866.332.8898 (English and French)

Outside North America 1.514.982.8717 (English and French)

 

SHAREHOLDER ACCOUNT MATTERS

For information regarding your shareholdings or to change your address, transfer shares, eliminate duplicate mailings, direct deposit of dividends, etc., please contact Computershare Investor Services Inc. If your shares are held by a broker, please contact your broker.

 

STOCK EXCHANGES

Cenovus common shares trade on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol CVE. Cenovus warrants trade on the TSX and the NYSE under the symbols TSX: CVE.WT and NYSE: CVE WS. Cenovus preferred shares Series 1, Series 2, Series 3, Series 5 and Series 7 trade on the TSX under the symbols CVE.PR.A, CVE.PR.B, CVE.PR.C, CVE.PR.E and CVE.PR.G.

 

ANNUAL INFORMATION FORM/FORM 40-F

Our Annual Information Form is filed with the Canadian Securities Administrators in Canada on SEDAR at sedar.com and with the U.S. Securities and Exchange Commission under the Multi- Jurisdictional Disclosure System as an Annual Report on Form 40-F on EDGAR at sec.gov.

 

NYSE CORPORATE GOVERNANCE STANDARDS

As a Canadian company listed on the NYSE, we are not required to comply with most of the NYSE corporate governance standards and instead may comply with Canadian corporate governance requirements. We are, however, required to disclose the significant differences between our corporate governance practices and those required to be followed by U.S. domestic companies under the NYSE corporate governance standards. Except as summarized on https://www.cenovus. com/about/governance/key-governance-documents.html, we are in compliance with the NYSE corporate governance standards in all significant respects.

 

 

   

INVESTOR RELATIONS

Please visit the Investors section at cenovus.com for investor information.

 

Investor inquiries should be directed to:

403.766.7711, investor.relations@cenovus.com

 

Media inquiries should be directed to:

403.766.7751, media.relations@cenovus.com

 

CENOVUS HEAD OFFICE

Cenovus Energy Inc.

225 6 Ave SW

PO Box 766

Calgary, Alberta T2P 0M5 Canada

Phone: 403.766.2000

cenovus.com

 

CENOVUS’S LEADERSHIP TEAM

(as at January 1, 2021)

Alex Pourbaix, President & Chief Executive Officer

Keith Chiasson, EVP, Downstream

Andrew Dahlin, EVP, Safety & Operations Technical Services

Rhona DelFrari, Chief Sustainability Officer & SVP,
    Stakeholder Engagement

Jeff Hart, EVP & Chief Financial Officer

Jon McKenzie, EVP & Chief Operating Officer

Gary Molnar, SVP, Legal, General Counsel & Corporate Secretary

Norrie Ramsay, EVP, Upstream – Thermal, Major Projects & Offshore

Kam Sandhar, EVP, Strategy & Corporate Development Sarah Walters, EVP, Corporate Services

Drew Zieglgansberger, EVP, Upstream – Conventional & Integration

 

CENOVUS’S BOARD OF DIRECTORS

(as at January 1, 2021)

Keith A. MacPhail, Board Chair, Calgary, Alberta (3,7)

Keith M. Casey, San Antonio, Texas (2,4)

Canning K. N. Fok, Hong Kong Special Administrative Region (6)

Jane E. Kinney, Toronto, Ontario (1,4)

Harold N. Kvisle, Calgary, Alberta (2,3)

Eva L. Kwok, Vancouver, British Columbia (2,3)

Richard J. Marcogliese, Alamo, California (1,4)

Claude Mongeau, Montreal, Québec (1,4)

Alex J. Pourbaix, Calgary, Alberta (5)

Wayne E. Shaw, Toronto, Ontario (1,4)

Frank J. Sixt, Hong Kong Special Administrative Region (3,6)

Rhonda I. Zygocki, Friday Harbor, Washington (2,3)

 

(1) Member of the Audit Committee

(2) Member of the Human Resources and Compensation (“HRC”) Committee

(3) Member of the Nominating and Corporate Governance (“NCG”) Committee

(4) Member of the Safety, Environment, Responsibility and Reserves (“SERR”) Committee

(5) As an officer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board

(6) Non-independent director

(7) An ex-officio non-voting member of the Audit Committee, HRC Committee and SERR Committee

 

 

   

 

 

 

 

 

 

 

 

LOGO

 

  

 

2020 ANNUAL REPORT  | 141

Table of Contents

LOGO



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