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

 

LOGO


Table of Contents

LOGO

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.

 

LOGO

LOGO

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.

 

     
 


Table of Contents

LOGO

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.

 

 

2020 ANNUAL REPORT  | 1


Table of Contents

    

LOGO

 

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

 

 

2 |  CENOVUS ENERGY


Table of Contents

LOGO

LOGO

 

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

 

 

2020 ANNUAL REPORT  | 3


Table of Contents

    

LOGO

 

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

 

 

4 |  CENOVUS ENERGY


Table of Contents

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.

 

 

2020 ANNUAL REPORT  | 5


Table of Contents

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.

 

6 |  CENOVUS ENERGY


Table of Contents

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,

 

2020 ANNUAL REPORT  | 7


Table of Contents

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

 

8 |  CENOVUS ENERGY


Table of Contents
 

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

 

2020 ANNUAL REPORT  | 9


Table of Contents

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.

 

10 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 11


Table of Contents
($ 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.

 

12 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 13


Table of Contents

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.

 

14 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 15


Table of Contents

 

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.

 

16 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 17


Table of Contents

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  
                                               

 

18 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 19


Table of Contents

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.

 

20 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 21


Table of Contents

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.

 

22 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 23


Table of Contents

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

 

24 |  CENOVUS ENERGY


Table of Contents

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

 

2020 ANNUAL REPORT  | 25


Table of Contents

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.

 

26 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 27


Table of Contents

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

 

28 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 29


Table of Contents

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

 

30 |  CENOVUS ENERGY


Table of Contents
 

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).

 

2020 ANNUAL REPORT  | 31


Table of Contents

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

 

32 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 33


Table of Contents
($ 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.

 

34 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 35


Table of Contents

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.

 

36 |  CENOVUS ENERGY


Table of Contents

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

 

2020 ANNUAL REPORT  | 37


Table of Contents

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.

 

38 |  CENOVUS ENERGY


Table of Contents

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.

 

2020 ANNUAL REPORT  | 39


Table of Contents

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.

 

40 |  CENOVUS ENERGY


Table of Contents

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

 

2020 ANNUAL REPORT  | 41


Table of Contents

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.

 

42 |  CENOVUS ENERGY


Table of Contents

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

 

2020 ANNUAL REPORT  | 43


Table of Contents

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

 

44 |  CENOVUS ENERGY


Table of Contents

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

 

2020 ANNUAL REPORT  | 45


Table of Contents

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

 

46 |  CENOVUS ENERGY


Table of Contents

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, whic