Exhibit 99.1

Cenovus reports second-quarter 2020 results

Company captures value by leveraging flexibility of its operations

Calgary, Alberta (July 23, 2020) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) remained focused on financial resilience in the second quarter of 2020 and used the flexibility of its assets and marketing strategy to adapt quickly to the changing external environment. This positioned the company to weather the sharp decline in benchmark crude oil prices in April by reducing volumes at its oil sands operations and storing the mobilized oil in its reservoirs for production in an improved price environment. While Cenovus’s financial results were impacted by the weak prices early in the quarter, the company captured value by quickly ramping up production when Western Canadian Select (WCS) prices increased almost tenfold from April to an average of C$46.03 per barrel (bbl) in June. As a result of this decision, Cenovus reached record volumes at its Christina Lake oil sands project in June and achieved free funds flow for the month of more than $290 million.

“We view the second quarter as a period of transition, with April as the low point of the downturn and the first signs of recovery taking hold in May and June,” said Alex Pourbaix, Cenovus President & Chief Executive Officer. “That said, we expect the commodity price environment to remain volatile for some time. We believe the flexibility of our assets and our low cost structure position us to withstand a continued period of low prices if necessary. And we’re ready to play a significant role in helping to lead Canada’s economic recovery.”

Response to COVID-19

In the first quarter of 2020, Cenovus responded quickly to the COVID-19 pandemic to protect the health and safety of its workforce and ensure the continuity of its business. In mid-March, the company moved to essential staffing levels at its field operations and directed the vast majority of its office staff to work from home. Cenovus continues to implement special measures and protocols to protect its workers. Some additional staff have recently started returning to field locations to address work that needs to be performed over the summer and fall while the return to offices is happening at a slower rate. Cenovus is monitoring the COVID-19 situation closely and will not compromise on the health and safety of its workers.

Business flexibility and balance sheet strength

In the second quarter of 2020, Cenovus remained focused on disciplined spending, maintaining its low cost structure and protecting its balance sheet. Capital investment in its oil sands and conventional segments decreased on a quarterly and year-over-year basis as a result of the decisive steps the company took in the first quarter of 2020 and in early April to respond to declining commodity prices and the rapid weakening of the business environment. During the second quarter, the company completed the previously announced temporary ramp-down of its crude-by-rail program.

In response to a 45% drop in the average price of West Texas Intermediate (WTI), to US$16.70/bbl, and a more than 70% decline in the average price of WCS, to C$4.92/bbl in April compared with March of 2020, Cenovus took additional steps to preserve value and protect its balance sheet by proactively managing its oil sands volumes. In April, the company voluntarily reduced oil sands production to just under 344,000 barrels per day (bbls/d), down 11% or approximately 44,000 bbls/d compared with March volumes. When WCS prices rebounded to C$46.03/bbl in June, Cenovus used the flexibility of its oil sands assets to quickly ramp up production and leveraged its range of transportation and marketing options, including storage and pipeline capabilities, to capture value from the higher prices. The company achieved average oil sands production of 405,658 bbls/d in June, which included a production record at Christina Lake.

“We made the strategic decision to use the flexibility of our business and relied on the collaboration of our upstream and marketing teams to manage the timing, storage and sales approach for our oil production,” said Pourbaix. “We are maximizing value for our shareholders even in this challenging economic environment.”  

Second-quarter financial results

Cenovus’s second-quarter adjusted funds flow shortfall of $462 million and free funds flow shortfall of $609 million were significantly impacted by losses of $529 million related to product sold in the quarter that was written down at the end of March. During the second quarter, essentially all the inventory that Cenovus wrote down in March was sold, and the company realized the inventory write-downs. The recovery in benchmark commodity prices and the ramp-up of production during the second quarter resulted in Cenovus achieving free funds flow of more than $290 million for the month of June.

The company recorded cash used in operating activities of $834 million in the second quarter compared with nearly $1.3 billion in cash from operating activities in the same

2

quarter of 2019. Cenovus had a second-quarter operating loss of $414 million and net loss of $235 million compared with operating earnings of $267 million and net earnings of almost $1.8 billion in the same period in 2019. The net loss was due to the lower operating earnings and unrealized risk management losses of $120 million, partially offset by non-operating unrealized foreign exchange gains of $273 million and a deferred income tax recovery of $131 million.

At the end of the second quarter, Cenovus had net debt of approximately $8.2 billion compared with net debt of about $7.4 billion at the end of the first quarter of 2020. The company continues to aim for a net debt level in the range of $5 billion or lower over the longer term.

Cenovus has $5.6 billion in committed credit facilities, a further $1.6 billion of uncommitted demand facilities and no bond maturities until late 2022. As of June 30, 2020, the company had drawn almost $1.5 billion against the committed credit facilities, $299 million against the uncommitted demand facilities, and there were outstanding letters of credit totaling $434 million. As at June 30, 2020 no amounts were drawn against the uncommitted demand facilities available to Cenovus’s refining partnership co-owned with Phillips 66.

Operating highlights

Cenovus’s upstream and refining assets continued to deliver safe and reliable operational performance during the second quarter.

Health and safety

Cenovus remains focused on delivering industry-leading safety performance through its focus on risk management and asset integrity. The company continued its excellent safety performance in the first half of 2020 with zero significant incidents and strong results in the prevention of recordable injuries and process safety events. This included a significant milestone by the Deep Basin conventional team, which achieved one year with zero recordable injuries.

Oil sands

For the second quarter, Christina Lake had average production of 207,157 bbls/d, while Foster Creek had average production of 166,032 bbls/d. The company achieved combined oil sands production of 373,189 bbls/d in the second quarter, compared with 344,973 bbls/d in the same period a year earlier. In May and June, Cenovus was able to produce above the government of Alberta’s mandatory production curtailment limit for industry due to the purchase of low-cost production credits from other companies. As a result, Christina Lake volumes increased from an average of 175,957 bbls/d for the month of April to an average of 242,964 bbls/d for the month of June, a record, underscoring Cenovus’s flexibility in managing through the volatile price environment.

Second-quarter oil sands operating costs were $7.36/bbl, down 15% from the same period a year earlier and 5% below the first quarter of 2020. The year-over-year decrease in oil sands operating costs was primarily due to higher sales volumes and the deferral of activity to manage costs in the low-price environment and limit field personnel due to COVID-19. The decrease in second-quarter operating costs from a year earlier was partially offset by higher fuel costs related to an increase in natural gas prices. In addition, Cenovus benefited

3

from a nearly 60% decrease in overall second-quarter transportation and blending costs compared with the first three months of 2020. The reduction was due to the suspension of the crude-by-rail program and associated variable costs as well as lower-priced condensate used for blending compared with the first three months of the year.

While Cenovus’s oil sands facilities were producing at reduced rates early in the second quarter, the company maintained normal steam production levels. This allowed Cenovus to continue operating the reservoirs effectively but also contributed to temporarily higher steam-to-oil ratios (SOR). At Christina Lake, the SOR was 2.1 in the second quarter, compared with 2.0 in the same period a year earlier. The SOR at Foster Creek was 2.8, up slightly from 2.7 a year earlier. The SORs are expected to track lower again as production increases.

Conventional

Cenovus’s conventional segment was previously referred to as the Deep Basin segment and now includes the Marten Hills asset. The comparative period has been restated to reflect this change.

Conventional production averaged approximately 92,000 barrels of oil equivalent per day (BOE/d) in the second quarter, a 6% decrease from the same period in 2019. The year-over-year decrease was due to natural declines from limited capital investment, partially offset by lower turnaround activity and fewer shut-ins in response to natural gas pricing compared with the same period in 2019 as well as the addition of Marten Hills heavy oil production starting in 2020. As previously announced, Cenovus has deferred the remainder of its 2020 drilling program in the conventional segment.

Total conventional operating costs declined 7% to $81 million in the second quarter of 2020 compared with the same period in the previous year. These cost savings are a result of the continued optimization of operations, focusing on critical repair and maintenance activities and increased use of Cenovus’s infrastructure. Per-barrel operating costs remained relatively flat at an average of $9.05/BOE compared with $9.01/BOE in the second quarter of 2019, as lower sales volumes and higher seasonal chemical purchases were offset by decreased property tax and lease costs as well as lower costs for repairs and maintenance. Second-quarter per-barrel operating costs remained flat from a year earlier even as production declined 6% over the same period.

Refining and marketing

Cenovus’s Wood River, Illinois and Borger, Texas refineries, which are co-owned with the operator, Phillips 66, had safe and reliable performance in the second quarter of 2020, while crude runs were affected by the economic slowdown due to COVID-19. Crude runs averaged 325,000 bbls/d in the second quarter, a 31% decrease from the same period in 2019.

Cenovus had refining and marketing operating margin of $134 million in the second quarter compared with $198 million in the same period of 2019, primarily due to reduced market crack spreads, lower crude oil runs and crude advantage, partially offset by higher margins on the sale of fixed-price products and lower operating costs.

4

Cenovus’s refining operating margin is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, operating margin from refining and marketing would have been $139 million lower in the second quarter, compared with $11 million higher in the same period in 2019.

While access to markets through new pipelines remains uncertain, Cenovus continues to look for opportunities to add value by finding new ways to get its products to new customers. In early July, the company announced its first-ever shipment of oil sands crude to Irving Oil’s refinery in Saint John, New Brunswick. Cenovus used its existing capacity on the Trans Mountain pipeline to ship oil to Burnaby, B.C., where it was loaded onto a tanker for a month-long voyage of approximately 11,900 kilometres south along the U.S. West Coast, through the Panama Canal and north to Saint John. Cenovus will continue to work with industry partners like Irving Oil to find innovative market-based solutions aimed at refining more Canadian oil in Canada, providing job opportunities and strengthening Canada’s economy.

Sustainability

On July 14, 2020, Cenovus released its 2019 environmental, social and governance (ESG) report. With the 2019 report, Cenovus has transitioned its approach to further align with the recommendations of the Task Force on Climate-related Financial Disclosure (TCFD) and, new this year, to follow the standards established by the Sustainability Accounting Standards Board (SASB). The report also incorporates references to the United Nations Sustainable Development Goals (SDGs).

Cenovus’s ESG report highlights the work the company has done to establish bold targets in four key ESG focus areas that are most impactful to its business: climate & greenhouse gas (GHG) emissions, Indigenous engagement, land & wildlife, and water stewardship. Cenovus continues to work on its plan for achieving its ESG targets over the next decade.

ADVISORY

Basis of Presentation

Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS).

Barrels of Oil Equivalent

Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) to one barrel (bbl). BOE may be misleading, particularly if

5

used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

Non-GAAP Measures and Additional Subtotal

This news release contains references to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted funds flow, free funds flow, operating earnings (loss) and net debt, which are non-GAAP measures, and operating margin, which is an additional subtotal found in Note 1 of Cenovus's Interim Consolidated Financial Statements for the period ended June 30, 2020 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus's website at cenovus.com). These measures do not have a standardized meaning as prescribed by IFRS. Readers should not consider these measures in isolation or as a substitute for analysis of the company's results as reported under IFRS. These measures are defined differently by different companies and therefore are not comparable to similar measures presented by other issuers. For definitions, as well as reconciliations to GAAP measures, and more information on these and other non-GAAP measures and additional subtotals, refer to “Non-GAAP Measures and Additional Subtotals” on page 1 of Cenovus's Management's Discussion & Analysis (MD&A) for the period ended June 30, 2020 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus's website at cenovus.com).

Forward-looking Information

This news release contains certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking information”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although Cenovus believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking information as actual results may differ materially from those expressed or implied.

Forward-looking information in this document is identified by words such as “achieving”, “aim”, “believe”, “committed”, “continue”, “ensure”, “expect”, “focus”, “opportunities”, “plan”, “position”, “protect”, “target” and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our expectations regarding the volatility of commodity prices and our ability to withstand an extended period of low oil prices; SORs expected to track lower as production increases; preserving the strength of our balance sheet; attaining long-term net debt level in the range of $5 billion or lower; uncertainty surrounding access to markets through new pipelines; opportunities to add value by finding new ways to get our products to new customers; working with industry partners to find innovative market-based solutions to refine more Canadian oil in Canada; delivering industry-leading safety performance through our focus on risk management and asset integrity; our four ESG focus areas and related targets and

6

ambitions; COVID-19-related special measures and protocols to protect workers and our approach to increasing staffing levels in the office and at field sites.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which our forward-looking information is based include, but are not limited to: forecast oil and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials and other assumptions identified in Cenovus’s 2020 guidance (dated April 1, 2020), available at cenovus.com; global demand for refined products will resume and prices will rise; continued access to short-term capital such as credit and demand facilities; continued impact of measures implemented to enhance the company’s resilience; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to our share price and market capitalization over the long term; future or continued narrowing of crude oil differentials; the ability of our refining capacity, dynamic storage, existing pipeline commitments and financial hedge transactions to partially mitigate a portion of our WCS crude oil volumes against wider differentials; our ability to adjust production while maintaining reservoir integrity; availability of new ways to get our products to new customers; opportunities to work with industry partners to find innovative market-based solutions aimed at refining more Canadian oil in Canada; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgments; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects, development programs or stages thereof; our ability to generate sufficient liquidity to meet our current and future obligations; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to develop, access and implement all technology and equipment necessary to achieve expected future results, and that such results are realized.

2020 guidance, dated April 1, 2020, assumes: Brent prices of US$39.00/bbl, WTI prices of US$34.00/bbl; WCS prices of US$18.50/bbl; Differential WTI-WCS of US$15.50/bbl; AECO natural gas prices of $2.00/Mcf; Chicago 3-2-1 crack spread of US$8.30/bbl; and an exchange rate of $0.70 US$/C$.

The risk factors and uncertainties that could cause our actual results to differ materially include, but are not limited to: volatility of and other assumptions regarding commodity prices, including the extent to which COVID-19 impacts the global economy and harms commodity prices; the extent to which COVID-19 and fluctuations in commodity prices associated with COVID-19 impacts our business, results of operations and financial condition, all of which will depend on future developments that are highly uncertain and difficult to predict, including, but not limited to the duration and spread of the pandemic, its severity, the actions taken to contain COVID-19 or treat its impact and how quickly economic activity normalizes; a resurgence in cases of COVID-19, which has occurred in certain locations and the possibility of which in other locations remains high and creates ongoing uncertainty that could result in restrictions to contain the virus being re-imposed or imposed on a more strict basis, including restrictions on movement and businesses; the success of our COVID-19 protocols and safety measures to protect workers; maintaining

7

sufficient liquidity to sustain operations through a prolonged market downturn; the duration of the market downturn; excessive widening of the WTI-WCS differential; unexpected consequences related to the Government of Alberta’s mandatory production curtailment; the effectiveness of our risk management program; the accuracy of cost estimates regarding commodity prices, currency and interest rates; product supply and demand; accuracy of our share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks, exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; our ability to maintain desirable ratios of net debt to adjusted EBITDA as well as debt to capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; accuracy of our reserves, future production and future net revenue estimates; accuracy of our accounting estimates and judgments; our ability to replace and expand oil and gas reserves; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of our assets or goodwill from time to time; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; our ability to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; unexpected cost increases or potential disruption or unexpected technical difficulties in developing new products and manufacturing processes and in constructing or modifying manufacturing or refining facilities; refining and marketing margins; cost escalations; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation and litigation related thereto; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to our business, including potential cyberattacks; risks associated with climate change and our assumptions relating thereto; our ability to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; possible failure to obtain and retain qualified staff and equipment in a timely and cost efficient manner; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political and economic conditions in the countries in which we operate or which we supply; the occurrence of unexpected events, such as pandemics, fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events, and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against us.

Statements relating to “reserves” are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the

8

reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of Cenovus’s material risk factors, refer to “Risk Management and Risk Factors” in the Corporation’s annual 2019 MD&A and the MD&A for the period ended June 30, 2020, and to the risk factors described in other documents Cenovus files from time to time with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Corporation’s website at cenovus.com.

Cenovus Energy Inc.

Cenovus Energy Inc. is a Canadian integrated oil and natural gas company. It is committed to maximizing value by sustainably developing its assets in a safe, innovative and cost-efficient manner, integrating environmental, social and governance considerations into its business plans. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and British Columbia. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. For more information, visit cenovus.com.

Find Cenovus on Facebook, Twitter, LinkedIn, YouTube and Instagram.

9

Exhibit 99.2

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) dated July 22, 2020, should be read in conjunction with our June 30, 2020 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2019 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2019 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of July 22, 2020, unless otherwise indicated. This MD&A provides an update to our annual MD&A and 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 interim MD&As and the annual MD&A are reviewed by the Audit Committee and recommended for approval by the Cenovus Board of Directors (the “Board”). Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.

Basis of Presentation

This MD&A and the interim 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 interim 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, or Advisory sections of this MD&A.

OVERVIEW OF CENOVUS

We are a Canadian integrated oil and natural gas company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. Operations include oil sands projects in northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our upstream assets averaged approximately 465,000 BOE per day for the three months ended June 30, 2020. We also conduct marketing activities and have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of 325,000 gross barrels per day of crude oil feedstock into an average of 332,000 gross barrels per day of refined products in the three months ended June 30, 2020.

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

Our Strategy

Our overall strategy remains unchanged and continues to be focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We have flexibility in our business plan that allows us to focus on maintaining liquidity and preserving a resilient balance sheet by reducing spending, while maintaining safe and reliable operations. This is particularly important in the current economic environment. However, our longer-term plan remains focused on sustainably growing shareholder returns and reducing Net Debt as well as continuing to integrate Environmental, Social and Governance (“ESG”) considerations into our business plan. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility. We aim to evaluate disciplined investment in our portfolio against dividends, share repurchases and achieving and maintaining the optimal debt level while targeting investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage. We plan to achieve our strategy by leveraging our strategic focus areas including our oil sands, conventional oil and natural gas assets, marketing, transportation and refining portfolio, and our people.

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

During the first quarter, COVID-19 reached a pandemic state. Measures taken by governments around the world to contain the virus significantly reduced demand for crude oil along with other products and services. This caused a significant slowdown in the global economy and in turn increased market volatility and led to a crash of global stock markets. At the same time, concerted 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, increasing overall global supply. The combination of these events resulted in a collapse of crude oil benchmark prices. West Texas Intermediate (“WTI”) benchmark crude oil prices went from nearly US$54.00 per barrel in late February to approximately US$20.00 per barrel at the end of March (averaging US$30.45 per barrel in March) and a further drop at the end of April to around US$19.00 per barrel (averaging US$16.70 per barrel in April). During the quarter, WTI benchmark prices ranged from a low of US$10.01 per barrel, excluding a historic one-day low of negative US$37.63 per barrel, to a high of US$40.46 per barrel, closing June at US$39.27 per barrel.

In April, OPEC and non-OPEC members, including Saudi Arabia and Russia, agreed to cut crude oil output in May and June, and several other countries announced similar production cuts. The decrease in the global supply of crude oil and the gradual increase in demand, as governments eased off on the measures taken to contain the pandemic, increased average WTI benchmark crude oil prices to US$28.53 per barrel in May and further increased it to US$38.31 per barrel in June.

We believe our reduced 2020 capital investment plan, operating cost reductions and general and administrative (“G&A”) reductions, announced on April 2, 2020, enhances our financial resilience and financial capability to maintain our base business, deliver safe and reliable operations, and to continue to challenge our cost structure in the face of these unprecedented conditions.

The Company has $5.6 billion in committed credit facilities, with $1.1 billion maturing in April 2021, $1.2 billion maturing in late 2022, and $3.3 billion maturing in late 2023. A further $1.6 billion of uncommitted demand lines are available to issue letters of credit or in some cases draw up to $600 million for general purposes, and the Company has no bond maturities until late 2022. We believe that we have ample liquidity and runway to sustain our operations through a prolonged market downturn. 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, not to exceed 65 percent. As at June 30, 2020, the Company was well below this limit.

The provincial and federal governments have recognized the serious economic impacts of the spread of COVID‑19 resulting in the collapse of oil prices and impact on the oil and gas industry and have taken steps to provide various programs, such as the Canada Emergency Wage Subsidy (“CEWS”) program. During the second quarter we have benefited 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 to help

prevent the spread of COVID-19 as non-critical staff, who are able to, work remotely. A phased and measured approach has been developed to return people back to our workplaces safely and gradually as essential work continues throughout the summer and fall to contribute to stimulating the economy. Increases in staff levels at sites and offices has and will continue to be achieved in accordance with guidance received from the Federal and Provincial governments and public health officials.

QUARTERLY OVERVIEW

During the second quarter, the COVID-19 pandemic and oversupply of crude oil impacted our business environment, operational decisions and financial results. Crude oil demand, severely impacted by COVID-19, began to show signs of recovery in the last two months of the second quarter with the easing of restrictions imposed by governments to limit the spread of the pandemic and commitment by OPEC and non-OPEC countries to reduce crude oil production levels.

Through this time, commodity prices have been low and extremely volatile. On April 20, 2020, the WTI May futures contract price fell sharply to close at a historic one-day low of negative US$37.63. During the quarter, WTI benchmark prices ranged from a low of US$10.01 per barrel, excluding the one-day close noted above, to a high of US$40.46 per barrel, closing June at US$39.27 per barrel. At the same time, the prices for Western Canadian Select (“WCS”) averaged a low of US$3.50 per barrel in April, rising to average US$33.97 per barrel in June. Average Brent and WTI crude oil benchmark prices for the second quarter were US$33.27 per barrel and US$27.85 per barrel, respectively. While there has been improvement in the prices through the quarter, they are still more than 50 percent lower than the second quarter of 2019. The duration of the commodity price environment continues to be uncertain and volatility continues, especially with fears of a potential second wave of COVID-19 infections driving concerns.

Operationally, our upstream assets performed well in the quarter and we continued to demonstrate good health and safety performance in light of the safety challenges presented by the pandemic. We reduced production volumes in response to the low crude oil pricing in April. As a result of the recovery in crude oil prices and access to additional production curtailment credits, we increased our production and achieved a record single-day production rate at Christina Lake in June. Overall, upstream production in the quarter, averaged 465,415 BOE per day, five percent higher than the second quarter of 2019. In the second quarter of 2019, production was reduced due to the planned turnaround at Christina Lake. Production from our Conventional assets was lower compared with the second quarter of 2019 due to natural well declines, partially offset by less turnaround activity, fewer shut-ins for low natural gas pricing, and added production in the Marten Hills area.

Our Wood River and Borger refineries (the “Refineries”) demonstrated good operational performance; however, the Refineries operated below capacity due to economic crude rate reductions in response to lower refined product demand as a result of COVID‑19. In the second quarter, we successfully completed the temporary ramp down of our crude-by-rail program.

In the second quarter, Upstream operating margin was $157 million compared with operating margin of $1,079 million in 2019, due to a lower average realized crude oil sales price, partially offset by lower royalties, lower transportation and blending costs, and higher sales volumes. Our average realized crude oil sales prices of $12.83 per barrel compared with $62.75 per barrel in the second quarter of 2019 decreased due to declining benchmark WTI prices, a wider WTI-WCS differential, and the use of condensate purchased when the condensate prices were higher. Upstream operating margin increased in the second quarter compared with negative $214 million in the first quarter of 2020, demonstrating some momentum of economic recovery.

Operating margin for our Refining and Marketing segment was $134 million in the second quarter, a decrease of $64 million compared with the second quarter of 2019 primarily due to decreased market crack spreads, reduced crude oil runs and lower crude advantage. The decrease was partially offset by higher realized margins on the sale of fixed price products and lower operating costs.

In the second quarter of 2020, we:

Upstream Production Volumes

Our upstream production for the three and six months ended June 30, 2020 increased compared with the same periods of 2019. Oil Sands production for the three months ended June 30, 2020 reflects our decision to operate at reduced levels in April in response to the low commodity price environment. When commodity prices began to improve in May and June, we increased our production, while utilizing additional production curtailment credits, to achieve a record single-day production rate at Christina Lake. In 2019, production was limited by the mandatory production curtailment limits set by the Government of Alberta, and in the second quarter of 2019, production was reduced due to the planned turnaround at Christina Lake. Production for the six months ended June 30, 2020 increased compared with 2019 due to the Special Production Allowance (“SPA”) program providing increased curtailment relief equivalent to incremental increases in crude shipped by rail in 2020 and the production outages due to the planned turnaround at Christina Lake noted above.

Conventional production in the three and six months ended June 30, 2020 decreased due to natural well declines, partially offset by less turnaround activity and fewer shut-ins for low natural gas pricing, as well as Marten Hills heavy oil production starting in 2020.

Refining and Marketing

Crude oil runs and refined product output decreased in the second quarter and on a year-to-date basis compared with the same periods in 2019 as both Refineries implemented crude rate reductions in response to reduced demand for refined products as a result of COVID-19. In 2019, both Refineries had unplanned outages in the second quarter which included impacts at Wood River related to pipeline outages and flooding on the Mississippi River. For the three and six months ended June 30, 2020, the economic crude rate reductions had a greater impact than planned and unplanned maintenance 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.

Operating Margin is an additional subtotal found in Note 1 of the interim Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, inventory write-downs, net of reversals, production and mineral taxes, plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.

Three Months Ended June 30, 2020 Compared With June 30, 2019

Operating Margin Variance

Operating Margin decreased in the three months ended June 30, 2020 compared with 2019 primarily due to a lower average crude oil sales price resulting from lower WTI benchmark pricing and wider WTI-WCS differentials, and lower Operating Margin from our Refining and Marketing segment primarily due to reduced market crack spreads, reduced crude oil runs and lower crude advantage, partially offset by higher margins on fixed price products and lower operating costs.

These decreases in Operating Margin were partially offset by:

Six Months Ended June 30, 2020 Compared With June 30, 2019

Operating Margin Variance

Operating Margin decreased in 2020 compared with 2019 primarily due to:

These decreases in Operating Margin were partially offset by:

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.

Cash Used in Operating Activities increased and Adjusted Funds Flow decreased for the three months ended June 30, 2020 compared with 2019, due to lower Operating Margin, as discussed above, and realized inventory write‑downs of $529 million, from both our Upstream and Refining and Marketing segments, partially offset by higher other income and lower current taxes. The change in non-cash working capital as presented in the interim Consolidated Statements of Cash Flows for the second quarter of 2020 was primarily due to an increase in accounts receivable, partially offset by a decrease in inventory due to the realization of the inventory write-downs in the quarter, and an increase in accounts payable. For the three months ended June 30, 2019, the change in non-cash working capital was due to a decrease in accounts receivable and lower income tax receivable, partially offset by a decrease in accounts payable and an increase in inventories.

Cash Used in Operating Activities increased and Adjusted Funds Flow decreased for the six months ended June 30, 2020 compared with 2019, due to lower Operating Margin, as discussed above, partially offset by higher other income, and lower current taxes. The change in non-cash working capital for the six months ended June 30, 2020 was primarily due to a decrease in accounts payable, partially offset by a decrease in inventory and accounts receivable. For the first six months of 2019, the change in non-cash working capital was primarily due to an increase in accounts receivable and increase in inventories, partially offset by a decrease in income tax receivable and an increase in accounts payable.

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.

In the second quarter of 2020, we had an Operating Loss compared with Operating Earnings in 2019 primarily due to lower Cash Used in Operating Activities and Adjusted Funds Flow, as discussed above, and a loss on the re‑measurement of the contingent payment of $64 million (2019 – $109 million gain), higher depreciation, depletion, and amortization (“DD&A”), partially offset by non-operating realized foreign exchange gains of $22 million compared with realized losses of $256 million on the repurchase of our unsecured notes in 2019.

Operating Loss increased for the six months ended June 30, 2020, relative to Operating Earnings in 2019 primarily due to lower Cash Used in Operating Activities and Adjusted Funds Flow, as discussed above, higher DD&A that included impairment losses of $315 million, and higher operating unrealized foreign exchange losses. The increase in our Operating Loss was partially offset by non-operating realized foreign exchange gains of $3 million compared with realized losses of $279 million in 2019 on our unsecured notes, a re‑measurement gain of $66 million on the contingent payment compared with a loss of $154 million in 2019, and lower non-cash employee long-term incentive costs.

Our Net Loss of $235 million in the second quarter of 2020 was lower than Net Earnings of $1,784 million in 2019 primarily due to lower Operating Earnings, as discussed above, a deferred income tax recovery of $131 million compared with $877 million in the second quarter of 2019, which included one-time recoveries related to the Alberta corporate tax rate change and tax basis increase related to our refining assets, unrealized risk management losses of $120 million compared with gains of $88 million in the second quarter of 2019, and non-operating unrealized foreign exchange gains of $273 million compared with unrealized gains of $407 million in 2019.

On a year-to-date basis, Net Loss of $2,032 million was significantly lower than Net Earnings of $1,894 million in the first half of 2019 due to lower Operating Earnings, as discussed above, non-operating unrealized foreign exchange losses of $316 million compared with unrealized gains of $616 million in 2019 and by a deferred income tax recovery of $479 million compared with a recovery of $836 million in 2019.

Capital investment in 2020 decreased compared with 2019, reflecting our reduced capital investment program and revised budget announced in April.

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

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.

Crude Oil Benchmarks

The average Brent and WTI crude oil benchmark prices in the second quarter declined 35 percent and 40 percent, respectively, relative to the first quarter of 2020. Year-over-year, the average Brent and WTI crude oil benchmark prices were lower due to the crude oil demand destruction caused by COVID-19. Continued uncertainty from decreased demand and oversupply of crude oil lowered benchmark prices. Global crude oil producers and refiners swiftly responded to the reduced demand by lowering supply in an attempt to rebalance the market, which supported improved pricing in May and June.

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 the second quarter, the Brent-WTI differential narrowed due to lower export demand for crude oil and reduced U.S. crude oil supply.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. Heavy oil differentials widened in the first quarter of 2020 in response to increased supply, as the Government of Alberta eased curtailment throughout 2019, as well as higher crude oil inventory levels and takeaway constraints (due to lower than expected crude-by-rail ramp-up for the oil and gas industry). In the second quarter of 2020, COVID-19 impacts resulted in reduced Western Canadian Select Basin (“WCSB”) supply causing differentials to significantly narrow as the WCSB crude supply was able to clear volumes by way of pipeline versus more expensive rail. 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. Weaker pricing at the USGC in the second quarter of 2020 was attributed to refiners lowering crude runs to adjust to reduced demand for products. The WCS at Hardisty spread to WCS at Nederland narrowed in the second quarter of 2020 compared with the same period of 2019 as a result of supply shut-ins in Alberta which reduced export capacity constraints.

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 compared with 2019 due to pipeline capacity additions in the latter part of 2019, less supply, and inventory builds at Cushing, Oklahoma. Average WTI-WTS differentials were at a premium in the second quarter of 2020 and a discount on a year-to-date basis compared with discounts in each respective period of 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 narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by 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 wider discount relative to WTI in Alberta in the second quarter of 2020 compared with 2019 due to lower diluent demand from heavy oil producers as a result of shutting in production. On a year-to-date basis, average condensate differentials to WTI narrowed compared with 2019.

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 significantly in the second quarter and on a year-to-date basis primarily due to lower product demand as a result of COVID-19. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by global prices, the strength 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.

Natural Gas Benchmarks

Average AECO prices strengthened during the three and six months ended June 30, 2020 compared with 2019 as associated gas from oil production decreased as producers shut-in wells. Average NYMEX prices decreased compared with 2019 due to lower demand.

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 the first half of the year. The weakening of the Canadian dollar relative to the U.S. dollar as at June 30, 2020 compared with December 31, 2019, resulted in unrealized foreign exchange losses of $316 million on the translation of our U.S. dollar debt.

REPORTABLE SEGMENTS

Our reportable segments are as follows:

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

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 the first quarter of 2020 and our new resource play, Marten Hills, was reclassified from the Oil Sands segment to the Conventional segment. Comparative periods have been reclassified.

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.

Oil Sands revenues decreased in the three and six months ended June 30, 2020 compared with 2019 due to lower average realized liquids sales price, partially offset by lower royalties and higher sales volumes.

Conventional revenues declined in the three and six months ended June 30, 2020 compared with 2019 due to lower average realized liquids sales prices and lower natural gas sales volumes, partially offset by lower royalties and the commencement of production from our Marten Hills asset.

Refining and Marketing revenues declined 62 percent in the second quarter and 43 percent on year-to-date basis compared with 2019. 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 for the three months ended June 30, 2020 compared with the same period in 2019 due to lower crude oil prices and lower natural gas volumes, partially offset by higher natural gas prices and crude oil volumes. On a year-to-date basis, marketing revenues 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.

OIL SANDS

In the second quarter of 2020, we: