Exhibit 99.1

Cenovus substantially achieves $7 billion near-term net debt target

Company generates over $830 million in second-quarter free funds flow

Calgary, Alberta (July 25, 2019) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) reduced net debt to $7.1 billion in the second quarter after generating over $830 million in free funds flow . The company’s excellent financial performance was driven by higher realized oil prices, which contributed to oil sands operating margin of more than $1.0 billion.

“Through focused operations and disciplined capital allocation, we have materially improved our balance sheet and achieved a very important milestone,” said Alex Pourbaix, Cenovus President & Chief Executive Officer. “As we relentlessly pursue getting our net debt even lower, to $5.0 billion, our balance sheet strength positions us to also consider opportunities for increasing shareholder returns and disciplined investments in our business.”  

Cenovus remains on track to increase its crude-by-rail capacity to approximately 100,000 barrels per day (bbls/d) by the end of 2019. In June, the company transported nearly 36,000 bbls/d of its oil by rail to the U.S. Gulf Coast. In the first quarter, Cenovus transported approximately 16,000 bbls/d of its oil by rail to the U.S. Gulf Coast, where the company can achieve higher pricing than by selling it in Alberta.

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Second- quarter overview

Balance sheet strength and capital discipline

During the first six months of 2019, Cenovus repurchased US$1.3 billion of unsecured notes for cash consideration of US$1.2 billion, including US$814 million in the second quarter. Net debt at the end of the second quarter was $7.1 billion. At current commodity prices, Cenovus expects to continue to make substantial progress towards its long-term net debt target of approximately $5.0 billion. At that level, the company anticipates being in a position to achieve and maintain a target ratio of less than two times net debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) at bottom-of-the-cycle commodity prices. At the end of the second quarter, Cenovus had net debt to adjusted EBITDA of 2.4 times.

Cenovus plans to provide investors with an update on its corporate strategy and five-year business plan, including future capital allocation priorities, at its scheduled Investor Day in Toronto on October 2, 2019.

Financial highlights

Cenovus’s strong second-quarter results were largely driven by a higher average realized crude oil price of $62.75 per barrel (bbl), up 22% from the same period in 2018. The company’s oil sands business had an excellent quarter focused on personal and process safety, cost control and production. Oil sands operating margin doubled to over $1.0 billion compared with the second quarter of 2018, even after accounting for the impact of a nearly month-long planned turnaround at Christina Lake, higher royalty payments and mandated production curtailments. The company’s safe and reliable operations, low cost structure and continued focus on capital discipline also contributed to its financial performance in the second quarter.

Cenovus generated second-quarter free funds flow of $834 million, up 73% from a year earlier, adjusted funds flow of approximately $1.1 billion, a 40% year-over-year increase, and cash from operating activities of nearly $1.3 billion, up 139% from the same period in 2018. In the first six months of the year, the company generated almost $1.6 billion in free funds flow, approximately $2.1 billion in adjusted funds flow and $1.7 billion in cash from operating activities.

“In late 2017, we implemented a plan to improve the resilience and competitiveness of our company ,” said Pourbaix . “Our excellent second-quarter results are a continuation and a reflection of our disciplined approach to operations, cost control and capital allocation. We continue to position ourselves to generate significant free funds flow in almost any commodity price environment.”

Cenovus’s operating earnings from continuing operations were $267 million compared with an operating loss of $292 million in the year-earlier period. Net earnings from continuing operations were approximately $1.8 billion in the second quarter compared with a net loss of $410 million in the same period in 2018. Net earnings included one-time deferred income tax recoveries of $658 million related to a reduction in Alberta’s corporate income tax rate and $387 million due to an increase in the tax basis of Cenovus’s U.S. refining assets. Non-operating unrealized foreign exchange gains of $407 million compared with losses of $205 million in the second quarter of 2018, and higher operating earnings also contributed to the year-over-year net earnings increase.

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Market access and sustainable oil production

Cenovus continues to pursue a diversified transportation strategy to get its oil to markets where it can achieve the highest price. This includes the company’s plan to ramp up its rail capacity to approximately 100,000 bbls/d in 2019, which remains on schedule.

“We view rail as a structural element of our market access strategy, but we cannot emphasize enough the importance of getting additional pipeline capacity out of Western Canada built,” said Pourbaix. “The unfounded attacks on our industry that have stalled new pipelines must be addressed for the benefit of all Canadians. Canadian oil is among the most responsibly produced in the world, and it makes no sense to stop it from reaching global customers.”

Cenovus and its peers continue to work on solutions to further reduce environmental impact , including water use, land footprint and greenhouse gas emissions. In addition to the significant results Cenovus and its peers have achieved to date, work is underway by companies individually and through collaborative efforts such as Canada’s Oil Sands Innovation Alliance (COSIA) and Evok Innovations , both of which Cenovus helped found.  

Advances in technology and operational efficiency have contributed to about a 30% reduction in Cenovus’s oil sands emissions intensity over the past 15 years. A barrel of oil produced at the company’s oil sands operations now has a lower emissions intensity than the average global barrel. Getting meaningful volumes of lower-emissions oil from Canada to global markets would provide an opportunity to replace more carbon-intensive barrels from other jurisdictions, helping to lower average global emissions. Further information about Cenovus’s approach to responsible development can be found in the company’s 2018 environmental, social & governance (ESG) report , which was published on July 23, 2019.

Production curtailment

Cenovus’s oil production continued to be limited by the Alberta government’s mandated production curtailment program in the second quarter, with oil sands volumes averaging 344,973 bbls/d, 11% lower than in the same period a year earlier. Based on mandated production volumes for July and August, the company anticipates average bitumen and crude oil production will be a maximum of 360,000 bbls/d for the third quarter. Production guidance for 2019 remains unchanged, with oil sands volumes expected to average between 350,000 bbls/d and 370,000 bbls/d for the year.

As a result of Alberta’s mandatory curtailment program, differentials between Western Canadian Select (WCS) and light oil benchmark prices have remained relatively narrow in 2019, contributing to improved financial performance for the Canadian oil industry and increased royalty payments. In Alberta, royalties on Cenovus’s production for the first six months of this year amount to more than $500 million. These royalties support the delivery of services and infrastructure such as health care, education, schools and roads.

“While curtailment was always meant to be a temporary measure, it’s doing what it was designed to do, and we expect the Alberta government will continue to use it as a tool while there is an inadequate balance between takeaway and production capacity in the province,” said Pourbaix. “In the near term, I’m optimistic that we’re beginning to see improved market access through the ramp-up of rail capacity and, over the longer term, through

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progress on pipeline solutions such as the Trans Mountain Expansion Project, Keystone XL and Enbridge’s Line 3 Replacement Program.”

Cenovus sees opportunity for the Alberta government to encourage increased movement of crude by rail by allowing producers to ship barrels in excess of mandated curtailment levels if those barrels are transported by rail. The company would also be supportive of the Government of Alberta divesting its contracted crude-by-rail capacity to industry.

Operating highlights

Safety

Following the previously announced safe completion of Cenovus’s winter delineation drilling and seismic work in the oil sands, the company successfully completed a nearly month-long planned turnaround at Christina Lake during April and May with no significant injury incidents and no process safety events. Company-wide, Cenovus continues to work towards achieving the internal safety targets it established for itself this year. The safety of Cenovus’s people, assets and the environment continues to be a top priority.

Oil sands

Second-quarter production at Christina Lake was 179,020 bbls/d, an 18% decrease compared with the same period in 2018, while Foster Creek averaged 165,953 bbls/d, 3% lower year-over-year. The decrease in volumes at both operations was primarily due to mandatory production curtailments. In addition, volumes at Christina Lake were reduced by 7,665 bbls/d during the second quarter due to the planned turnaround.

On July 10, 2019, Foster Creek and Christina Lake, which have been operating since 1997 and 2002 respectively, reached one billion barrels of cumulative oil sands production. Cenovus is the first oil sands operator to achieve one billion barrels of production using steam-assisted gravity drainage (SAGD) technology. The success of SAGD has resulted in over $25 billion in investment in the Canadian economy by Cenovus and its predecessor companies, and substantially more by the oil sands industry as a whole, for the benefit of all Canadians.

While Cenovus’s oil sands facilities are producing at lower rates to comply with mandated curtailment, the company is maintaining normal steam injection levels. This allows Cenovus to continue mobilizing and storing production-ready barrels in its reservoirs, so it can efficiently increase production volumes when mandatory curtailment is eased. Maintaining normal steam injection rates during curtailment has contributed to a modest, temporary increase in per-barrel operating costs and steam-to-oil ratios (SORs). SOR is the amount of steam needed to produce one barrel of oil.

At Christina Lake, the SOR was 2.0 in the second quarter, compared with 1.8 in the second quarter of 2018. At Foster Creek, the SOR was 2.7 compared with 2.6 a year earlier.

Cenovus had second-quarter oil sands operating costs of $8.70/bbl, up 19% from the same period a year ago. The increase in per-barrel operating costs was mainly the result of lower sales volumes, increased repairs and maintenance and higher fluid waste handling and trucking costs related to the planned turnaround at Christina Lake. Operating cost increases were partially offset by lower chemical costs. Cenovus achieved second-quarter oil sands

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netbacks, excluding realized hedging impacts, of $ 35.78 /bbl , a 10% increase from the second quarter of 2018.

Cenovus continues to have flexibility on timing with its newly-completed phase G expansion at Christina Lake and will consider ramping up incremental oil production once the company has clarity on market access and the duration of production curtailments .

Deep Basin

Deep Basin production averaged 98,345 barrels of oil equivalent per day (BOE/d) in the second quarter, a 24% decrease from year-earlier levels, partly due to lower capital investment, the September 2018 divestiture of the Pipestone business and expected natural declines. In the latter part of the second quarter, production was also impacted by Cenovus’s decision to shut in some volumes due to low natural gas prices. The vast majority of these wells have since returned to production.

Average operating costs in the Deep Basin were $9.01/BOE in the second quarter, up 4% from $8.68/BOE a year earlier. The increase in per-barrel operating costs was driven by lower sales volumes, partially offset by reduced repairs and maintenance activity, lower processing fees due to reduced throughput as well as decreased chemical, electrical and workforce costs.

Cenovus continues work to optimize its Deep Basin operating model with a view to reducing costs, improving efficiency and maximizing value.

Downstream

Cenovus’s Wood River, Illinois and Borger, Texas refineries, which are co-owned with the operator, Phillips 66, delivered solid operational performance in the second quarter, with plant utilization rates of around 98%. Performance at Wood River was partially impacted by crude pipeline outages and flooding on the Mississippi River.  

Refining and marketing operating margin was $198 million in the second quarter, compared with operating margin of $357 million in the year-earlier period, largely due to lower crude advantage from narrowing heavy and medium sour crude oil differentials as well as higher operating costs and unplanned maintenance at both refineries. 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 $10 million higher in the second quarter, compared with $57 million lower in the same period of 2018.

Board renewal

M. George Lewis has been appointed to Cenovus’s Board of Directors, effective immediately. Mr. Lewis was with Royal Bank of Canada (RBC) for 30 years, including serving on the company's Group Executive. Currently, he is a member of the Board of Directors of the Ontario Teachers’ Pension Plan Board and Legal & General Group plc (UK).

“George Lewis brings strong financial services experience with a focus on asset and capital management following a 30-year career with RBC,” said Patrick D. Daniel, Chair of the Board of Directors. “His expertise and experience will be a substantial benefit to Cenovus.”

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Dividend

For the third quarter of 2019, the Board of Directors declared a dividend of $0.05 per share, payable on September 30, 2019 to common shareholders of record as of September 13, 2019. Based on the July 24, 2019 closing share price on the Toronto Stock Exchange of $12.29, this represents an annualized yield of approximately 1.6%. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis.

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 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 funds flow, free funds flow, netback, operating earnings (loss), net debt, and net debt to adjusted EBITDA, which are non-GAAP measures, and operating margin, which is an additional subtotal found in Note 1 of Cenovus's Interim Consolidated Financial Statements (unaudited) for the period ended June 30, 2019 (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, 2019 (available on SEDAR at sedar.com , on EDGAR at sec.gov and Cenovus's website at cenovus.com ).

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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 “anticipate”, “expect”, “focus”, “guidance”, “on track”, “plan”, “target”, “will”, “with a view”, “would be”, “see”, or similar expressions and includes suggestions of future outcomes, including statements about: strategy and related milestones and schedules; projections for 2019 and future years and our plans and strategies to realize such projections; priorities and other statements relating to forecast capital discipline and investment, production guidance and debt reduction; ability to generate substantial cash flow, adjusted funds flow and free funds flow in the current commodity price environment; targeted reductions of net debt to $5.0 billion; the impact of the Alberta government mandated production curtailment; expected ramp-up of rail commitments; the planned timeline for ramping up oil-by-rail movement; pipeline capacity commitments; Christina Lake phase G expansion start-up flexibility; and all statements related to the company’s 2019 Guidance.

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: updated price and sensitivities assumptions as disclosed in the following table, available in Cenovus’s 2019 Guidance (dated April 23, 2019) at cenovus.com ;

projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; achievement of further operating efficiencies, cost reductions and sustainability thereof; lower production as a result of the government-mandated production curtailment contributing to improvement in WCS prices, narrowing of the price differential between WTI and WCS; future improvements in availability of product transportation capacity, including Canadian oil-by-rail activity ramping up as planned; realization of expected impacts of the company's storage capacity within its oil sands reservoirs; the

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ability of our refining capacity, existing pipeline commitments and plans to ramp up crude-by-rail loading capacity to mitigate a portion of heavy oil volumes against wider differentials; continued improved Canadian commodity prices; bottom-of-the-cycle commodity prices of US$45/bbl WTI and C$44/bbl WCS; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgments; future use and development of technology and associated expected future results; ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; ability to complete asset sales, including with desired transaction metrics and expected timelines; and ability to access and implement all technology necessary to achieve expected future results.

Additional information about risks, assumptions, uncertainties and other factors that could influence Cenovus’s actual results is provided in Cenovus’s MD&A for the year ended December 31, 2018 and its MD&A for the period ended June 30, 2019 as well as its AIF and Form 40-F for the year ended December 31, 2018 (all available on SEDAR at sedar.com , on EDGAR at sec.gov and Cenovus's website at cenovus.com ).

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause Cenovus's actual results to differ materially from those estimated, projected, expressed, or implied by the forward-looking information. Cenovus undertakes no obligation to update or revise any forward-looking information except as required by law.

Cenovus Energy Inc.

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

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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 24, 2019, should be read in conjunction with our June 30, 2019 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2018 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2018 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of July 24, 2019, 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 are approved by the Audit Committee of the Cenovus Board of Directors (the “Board”) and the annual MD&A is reviewed by the Audit Committee and recommended for approval by 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. We adopted IFRS 16, “Leases” (“IFRS 16”), effective January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A for further information.

Non-GAAP Measures and Additional Subtotals

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow, Operating Earnings, Free Funds Flow, Debt, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) and therefore are considered non-GAAP measures. In addition, Operating Margin is considered an additional subtotal found in Notes 1 and 7 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 Results, Financial Results, Liquidity and Capital Resources, or Advisory sections of this MD&A.

OVERVIEW O F CENOVUS

We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On June 30, 2019, we had an enterprise value of approximately $22 billion. Operations include oil sands projects in northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our upstream assets averaged approximately 443,000 BOE per day for the three months ended June 30, 2019. We also conduct marketing activities and have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of 474,000 gross barrels per day of crude oil feedstock into an average of 501,000 gross barrels per day of refined products in the three months ended June 30, 2019.

Our strategy is focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility and give us the flexibility to proceed with opportunities at all points in the price cycle. We aim to evaluate disciplined investment in our portfolio against dividend increases, share repurchases and maintaining the optimal debt level while retaining investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage. We plan to achieve our strategy by leveraging our strategic focus areas including oil sands, conventional oil and natural gas assets, marketing, transportation and refining portfolio, and our people.

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

QUARTERLY HIGHLIGHTS

Cenovus delivered solid operating and financial results in the second quarter of 2019 and made significant progress on further deleveraging the balance sheet. We repurchased US$814 million of our unsecured notes during the quarter and US$1.3 billion since the beginning of the year.

Our upstream operational performance was solid during the quarter with production averaging 443,318 BOE per day, restricted by the Government of Alberta’s mandatory production curtailment program and the planned turnaround completed at Christina Lake.

Refining and Marketing operations were solid with improved crude oil runs in second quarter of 2019 compared with 2018, despite unplanned outages at both the Wood River and Borger refineries (“the Refineries”). Our Refining and Marketing segment generated operating margin of $198 million down from the second quarter of 2018, due to lower crude advantage and higher operating costs, partially offset by higher crack spreads.

With market access constraints for Canadian crude oil production continuing to be a challenge, we have made good progress on our strategy to maintain firm transportation through a combination of pipelines, rail and marine access. In the second quarter of 2019, we received approximately one-third of the railcars under the agreements signed in late 2018. Delivery will continue through 2019, in line with our expected ramp up to 100,000 barrels per day shipped by rail. We have also secured additional storage capacity in the U.S. Gulf Coast to support the ramp up of our crude-by-rail activity.

Average Brent and West Texas Intermediate (“WTI”) benchmark prices were lower than the second quarter of 2018. At the same time, the differential between WTI and Western Canadian Select ("WCS") benchmark prices narrowed 45 percent, supported by the Government of Alberta’s mandatory production curtailment program. As a result, WCS benchmark crude oil prices remained relatively flat, averaging US$49.18 per barrel in the second quarter of 2019 compared with US$48.61 per barrel in the same period of 2018. Our realized crude oil sales price rose to $62.75 per barrel as a result of the higher WCS price along with lower cost of condensate due to lower condensate benchmark prices compared with the second quarter of 2018.

In the second quarter of 2019, we:

Overall, production for the three and six months ended June 30, 2019 was in line with production limits set by the Government of Alberta. Oil Sands production for the three and six months ended June 30, 2019 was limited due to mandatory production curtailments and a planned turnaround at Christina Lake. During the quarter, production decreased by 7,665 barrels per day due to the turnaround, minimized by additional plant capacity from the Christina Lake phase G facility and production capability from Foster Creek. In 2018, Oil Sands production was impacted by our decision to reduce producing well rates in the first quarter due to pipeline capacity constraints and discounted heavy oil prices and the subsequent ramp up of production in the second quarter as differentials narrowed.

Deep Basin production for the three months ended June 30, 2019 averaged 98,345 BOE per day compared with 129,066 BOE per day in the second quarter of 2018 due to lower sustaining capital investment, the divestiture of Cenovus Pipestone Partnership (“CPP”) on September 6, 2018, natural declines and a temporary shut-in to manage low gas prices. This was partially offset by less downtime in the second quarter of 2019 compared with 2018. Deep Basin production for the six months ended June 30, 2019 decreased by 21 percent to 101,301 BOE per day compared with 2018 due to lower sustaining capital investment, the divestiture of CPP and natural declines, partially offset by less downtime.

Netbacks From Continuing Operations

Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see the Advisory section of this MD&A.

Our average Netback, excluding realized risk management gains and losses, increased in the second quarter of 2019 and on a year-to-date basis, compared with 2018, primarily due to higher realized sales prices and lower transportation and blending costs, partially offset by higher royalties, higher per-unit operating costs and lower sales volumes. Higher royalties were driven by higher prices and our Christina Lake property achieving payout in the third quarter of 2018. On a quarterly and year-to-date basis, the weakening of the Canadian dollar relative to the U.S. dollar compared with 2018 had a positive impact on our reported sales price of approximately $2.03 per BOE and $2.21 per BOE, respectively.

Refining and Marketing

In the second quarter of 2019, both refineries demonstrated good operational performance with crude utilization rates averaging 98 percent. Wood River was impacted by pipeline outages and flooding on the Mississippi River, which resulted in the reduction of throughput to manage finished product inventories. On a year-to-date basis, crude oil runs and refined product output increased as planned and unplanned maintenance in 2019, including a fire in a crude unit at Wood River in the first quarter of 2019, had less of an impact than major planned turnarounds completed at both Refineries in the first quarter of 2018.

We continue to increase total rail volumes loaded at our Bruderheim crude-by-rail terminal. In the three months ended June 30, 2019, we loaded an average of 53,539 barrels per day at our Bruderheim crude-by-rail terminal compared with an average of 21,756 barrels per day in the second quarter of 2018.

Operating Margin from the Refining and Marketing segment in the three and six months ended June 30, 2019 was $198 million and $502 million, respectively (2018 – $357 million and $309 million, respectively). Our Operating Margin in the second quarter of 2019 decreased compared with 2018 due to lower crude advantage from narrowing heavy and medium sour crude oil differentials, and higher operating costs related to labour and unplanned maintenance at both Refineries. Operating margin improved significantly year-over-year, primarily due to lower operating expenses as a result of major planned turnarounds at both Refineries in the first quarter of 2018, higher

market crack spreads, higher margins on fixed priced products due to a lower benchmark WTI, and a reduction in the cost of Renewable Identification Numbers (“RINs”) , partially offset by a reduced crude advantage from narrowing heavy and medium sour crude oil differentials .

Further information on the changes in our production volumes and other items included in our Netbacks, and refining results can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the interim Consolidated Financial Statements.

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.

Crude Oil Benchmarks

The average Brent and WTI crude oil benchmark prices were lower compared with the second quarter of 2018. Continued uncertainty from oversupply and decreased demand for crude oil due to U.S.-China trade tensions lowered crude oil benchmark pricing. Global prices continued to be supported by the Organization of the Petroleum Exporting Countries (“OPEC”) led production cuts over the first six months of 2019 compared with the same period of 2018. Crude oil prices were further supported by turmoil in Venezuela that reduced the country’s crude oil supply. The decrease of crude oil supply from Venezuela coupled with OPEC cuts, which are predominately medium and heavy weighted crudes, reduced heavy crude supply globally causing WCS prices in the U.S. Gulf Coast to strengthen from the first quarter of 2019.

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 of 2019, the Brent-WTI differential increased compared with 2018 as a result of increasing U.S. supply and inventory builds exceeding pipeline takeaway capacity at Cushing, Oklahoma.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed in the second quarter of 2019 and on a year-to-date basis compared with 2018. Heavy oil differentials have narrowed in 2019 in response to production curtailments mandated by the Government of Alberta to address record high differentials in the fourth quarter of 2018 and high levels of crude oil in storage. Decreased production due to mandatory curtailments continues to support Alberta benchmark prices.

WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI crude oil, and is a primary component of the input feedstock at the Borger refinery. The differential between WTI and WTS benchmark prices narrowed in 2019 compared with 2018, due to additional pipeline capacity coming online, helping to debottleneck the Permian Basin.

Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent volumes as a percentage of total blended volumes, range from approximately 25 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the cost to transport the condensate to Edmonton.

Average condensate benchmark prices were discounted relative to WTI in the second quarter of 2019 and on a year-to-date basis compared with a premium in the same periods of 2018 due to increasing domestic supply and lower demand as production curtailments were implemented.

MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production, comparable to the crude oil produced by our Deep Basin assets. The average MSW benchmark price declined in the second quarter of 2019 compared with 2018, consistent with the general decrease in average crude oil prices.

Refining Benchmarks

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

Average Chicago refined product prices decreased on a year-to-date basis in 2019 compared with the same period of 2018 primarily due to lower global crude oil prices. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by international prices, the strength of refining crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and WTI benchmark prices. The widening of the

Chicago 3-2-1 and Group 3 crack spread s in 2019 can be primarily attributed to the widening of the Brent-WTI differential, as discussed above .

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, 2019 compared with 2018 due to strong weather induced demand and flat natural gas supply in Alberta. Average NYMEX prices were comparable with 2018 due to supply continuing to be high from the development of U.S. shale gas and natural gas associated with crude oil plays.

Foreign Exchange Benchmark

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

The average Canadian dollar weakened relative to the U.S. dollar in 2019, compared with 2018, resulting in a positive impact of approximately $445 million on our revenues in the first half of the year. The strengthening of the Canadian dollar relative to the U.S. dollar as at June 30, 2019 compared with December 31, 2018, and the derecognition of unrealized foreign exchange losses, which were realized due to the repurchase of our unsecured notes, resulted in $628 million of unrealized foreign exchange gains on the translation of our U.S. dollar debt.