Report of Foreign Issuer (6-k)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 

under the Securities Exchange Act of 1934

For April 2018

Commission File Number:  1-34513

CENOVUS ENERGY INC.

(Translation of registrant’s name into English)

2600, 500 Centre Street S.E.

Calgary, Alberta, Canada T2G 1A6

(Address of principal executive office)

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

Form 20-F  ☐    Form 40-F  ☒

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

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

Exhibit 99.2, 99.3 and 99.4 to this report, furnished on Form 6-K, shall be incorporated by reference into or as an exhibit to, as applicable, each of the registrant’s Registration Statements under the Securities Act of 1933: Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165), and Form F-10 (File No. 333-220700).

DOCUMENTS FILED AS PART OF THIS FORM 6-K

See the Exhibit Index to this Form 6-K.

SIGNATURES

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

Date:  April 25, 2018

Form 6-K Exhibit Index

Exhibit 99.1

Cenovus delivers strong first quarter operational performance

Financial results impacted by hedging and price differentials

Calgary, Alberta (April 25, 2018) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) had continued strong operational performance from its oil sands projects and Deep Basin natural gas assets in the first quarter of 2018. The company’s quarterly financial results were impacted by risk management losses, wider light-heavy oil differentials and planned refinery maintenance. As previously announced, Cenovus responded to the wider price differentials and transportation constraints by temporarily slowing oil sands production in February and March and storing excess barrels in its reservoirs. The company ramped oil sands production back up to normal levels after Western Canadian Select (WCS) prices improved. Cenovus also made good progress with its drilling program in the Deep Basin in the quarter.

First quarter highlights

¹ Includes results from Cenovus’s legacy conventional segment, which has been classified as a discontinued operation.

² Adjusted funds flow, free funds flow and operating earnings/loss are non-GAAP measures. See Advisory.

³ Does not include production from Cenovus’s legacy conventional oil and natural gas assets, the last of which was sold as of January 5, 2018. The legacy conventional segment has been classified as a discontinued operation.

⁴ Includes oil and natural gas liquids (NGLs).

⁵ Totals may not add due to rounding.

First quarter overview

Financial highlights

In the first quarter of 2018, Cenovus had a shortfall in cash from operating activities of $123 million compared with a surplus of $328 million in the same period a year earlier, and a shortfall in adjusted funds flow of $41 million, compared with a surplus of $323 million in 2017. Operating loss from continuing operations was $752 million compared with a $39 million loss the previous year.

Financial results were affected by realized risk management losses, the widest light-heavy oil price differentials experienced since the fourth quarter of 2013, planned turnarounds at the company’s two jointly owned U.S. refineries and an impairment on some assets in the Deep Basin.

“The challenges we experienced in the first quarter had a significant impact on our financial results, but the underlying performance of our assets remains very strong,” said Alex Pourbaix, Cenovus President & Chief Executive Officer. “I want to stress that these financial challenges are temporary and don’t reflect Cenovus’s significant potential for funds flow and earnings growth.”

Cenovus incurred realized risk management losses from continuing operations of $469 million compared with losses of $79 million in the same quarter a year earlier. Following the company’s May 2017 asset acquisition, Cenovus had increased leverage and was in the process of marketing its legacy conventional oil and natural gas assets to streamline its portfolio and reduce debt. The company hedged approximately 80% of its forecast oil production for the first half of 2018 to support financial resilience by establishing downside protection at a time when commodity prices were lower and the timing and amount of proceeds from planned divestitures were uncertain. This was the main contributor to the realized risk management losses in the quarter as benchmark prices exceeded Cenovus’s contract prices.

At the end of the second quarter, a portion of Cenovus’s 2018 risk management contracts will expire, reducing the company’s hedge position to approximately 37% of forecast oil production for the second half of the year. As of March 31, 2018, the company had 19,000 barrels per day (bbls/d) of West Texas Intermediate (WTI) hedged for 2019 using collars that provide downside price protection while allowing Cenovus opportunity to capture some of the benefit in a rising price environment.

During the first quarter of 2018, transportation constraints resulted in light-heavy oil price differentials averaging US$24.28/bbl, 67% wider compared with the same period in 2017. This contributed to reduced netbacks at the company’s oil sands operations. Companywide netbacks from continuing operations, before realized risk management losses, averaged $16.80 per barrel of oil equivalent (BOE) in the first quarter of 2018 compared with $21.25 in the same period a year earlier. Cenovus continues to mitigate its exposure to heavy oil price discounts through its downstream integration, pipeline commitments to the U.S. Gulf Coast and Canadian West Coast and rail optionality including the company’s Bruderheim crude-by-rail terminal as well as through financial contracts on the WCS differential.

At Cenovus’s jointly owned Wood River and Borger refineries in the U.S., the operator carried out major planned turnarounds over several weeks during the first quarter. As a result, Cenovus recorded a shortfall in refining and marketing operating margin of $48 million for the quarter, compared with operating margin of $53 million in the same period of 2017. 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, the shortfall in operating margin from refining and marketing would have been $69 million in the first quarter of 2018.

As at the end of the first quarter, Cenovus determined that the carrying value of its Clearwater assets in the Deep Basin exceeded their recoverable amount due to a decline in forward natural gas prices. This resulted in a non-cash impairment charge of $100 million in the quarter.

Cost reductions

Cenovus continues to make progress in reducing the company’s capital investment costs and operating and general and administrative (G&A) expenses. This includes the company’s previously announced plan to reduce its workforce by approximately 15% from 2017 levels, which is now largely complete.

Cenovus continues to achieve greater operational and capital efficiencies by drilling longer horizontal wells in the oil sands and using multi-well pad development in the Deep Basin. Previous improvements to electric submersible pumps at the company’s oil sands operations have resulted in longer pump life and reduced workover costs. Lower decline rates and better performance from new well pads at Cenovus’s oil sands facilities have allowed the company to optimize timing of wells and capital investment, further reducing costs. In the Deep Basin, optimization of maintenance and integrity programs lowered repair and maintenance expenses. Additional per-barrel operating cost reductions are expected to come with further optimization of maintenance scheduling.

Cenovus had first quarter G&A costs of $179 million, compared with $43 million in the same period in 2017. The increase was primarily due to one-time severance costs of $43 million and a $59 million non-cash expense for Calgary office space that exceeds current needs. Cenovus continues to pursue an active subleasing program to offset some of its real estate costs.

Divestitures and deleveraging

In January 2018, Cenovus closed the sale of its Suffield assets for gross cash proceeds of $512 million. With the closing of the Suffield sale, the company completed its plan, announced in 2017, to divest its legacy conventional business.

To further streamline its portfolio, reduce debt and increase shareholder value, the company continues to review potential divestitures of non-core assets in the Deep Basin. Cenovus has one of the largest land positions in the Deep Basin, with approximately three million net acres, providing more opportunities than the company can efficiently develop within a reasonable timeframe. The company continues to make progress with its previously announced plan to sell assets with current production of approximately 15,000 BOE/d of natural gas and liquids in the Clearwater area of the Deep Basin.

Operating highlights

Oil sands

Cenovus’s oil sands projects continued to deliver strong operational performance in the first quarter of 2018. However, due to market access challenges, the company decided to temporarily slow production at Christina Lake and Foster Creek in February and March.

“After a strong operational start to the quarter, we took prudent steps to reduce production volumes in response to wider light-heavy differentials, export pipeline capacity constraints and the slow pace of ramp up in oil-by-rail capacity,” said Pourbaix. “When Canadian heavy oil is selling at a wide discount to WTI, we have the ability to slow our oil sands production while maintaining steam injection to mobilize the oil. We can then store that mobilized oil in our reservoirs to be produced and sold at a later date when pipeline capacity improves and differentials narrow.”

To help address these ongoing market access challenges, Cenovus is working with rail providers to resolve a shortage of locomotive hauling capacity so that the company can more fully realize the benefits of its Bruderheim crude-by-rail facility. Cenovus expects overall industry rail access to improve starting in the second half of the year. Should rail capacity improvements take longer than expected, or pipeline capacity tighten again, the company may take further steps to defer production which could result in fluctuating production volumes from month to month.

As a result of the temporary oil sands production decrease in the first quarter, Foster Creek’s steam to oil ratio (SOR) – the amount of steam needed to produce one barrel of oil – rose to 2.8 for the period. As market access improved in late March and April, Cenovus ramped oil sands production back up to take advantage of improved pricing. At Christina Lake, the SOR remained unchanged year over year at an industry leading 1.8. The company expects SORs to remain within full-year guidance of 2.6 to 3.0 at Foster Creek and 1.8 to 2.2 for Christina Lake in 2018.

Combined production at Christina Lake and Foster Creek was 359,666 bbls/d during the quarter, nearly double the volume from the same period a year earlier. The increase was due to the company’s May 2017 acquisition, which resulted in Cenovus taking full ownership of its oil sands assets. Oil sands operating expenses were $8.78/bbl, 2% lower than in the first quarter of 2017. Cenovus continues to expect full-year oil sands volumes for 2018 to be within its guidance range of 364,000 to 382,000 bbls/d.

Construction at the Christina Lake phase G expansion, which resumed in the first quarter of 2017, continues to progress on time and on budget. Cenovus expects the expansion will have go-forward capital costs, from the time the project was restarted last year through to completion, of between $13,000 and $14,000 per flowing barrel compared with the company’s previous estimate of between $16,000 and $18,000. Phase G has approved capacity of 50,000 bbls/d.

Deep Basin

To date, Cenovus is pleased with its Deep Basin program and initial well results have met or exceeded the company’s expectations. First quarter production averaged 127,056 BOE/d, with average operating costs of $7.36/BOE, an 18% reduction from the third quarter of 2017, Cenovus’s first full quarter of ownership of the assets. While the company is

encouraged by the drilling and production results, Cenovus continues to take a disciplined approach to development in the Deep Basin in response to lower natural gas prices. During the quarter, the company substantially completed its 2018 Deep Basin capital investment program, bringing 17 wells on production, completing 16 wells and adding additional pipeline infrastructure, and drilling 14 horizontal wells targeting liquids-rich natural gas.

Downstream

In the first quarter of 2018, the Wood River and Borger refineries, which Cenovus jointly owns with the operator, underwent planned maintenance activity, including the first major turnaround at the Wood River Coker and Refinery Expansion (CORE) project since it was completed in 2011. The maintenance programs were completed in April, and both refineries have since returned to planned operating levels.

New CFO appointed

Earlier this month, Cenovus announced the appointment of Jon McKenzie as the company’s next Chief Financial Officer, who in addition to his financial background brings a broad range of energy industry experience spanning operations, supply, trading and commercial activities related to pipelines, rail and terminal operations. He will succeed Ivor Ruste, who, as previously announced, is retiring on April 30.

Dividend

For the second quarter of 2018, the Board of Directors has declared a dividend of $0.05 per share, payable on June 29, 2018 to common shareholders of record as of June 15, 2018. Based on the April 24, 2018 closing share price on the Toronto Stock Exchange of $12.19, this represents an annualized yield of about 2%. 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, operating earnings (loss), net debt, net debt to adjusted EBITDA, and netback, 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 March 31, 2018 (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” and the Advisory section of Cenovus's Management's Discussion & Analysis (MD&A) for the period ended March 31, 2018 (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 Cenovus's current expectations, estimates and projections about the future, based on certain assumptions made in light of Cenovus's 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.

Forward-looking information in this document is identified by words such as “budget”, “capacity”, “estimate”, “expect”, “focus”, “forecast”, “forward”, “mitigate”, “on time”, “position”, “potential”, “progress”, “target”, “will”, or similar expressions and includes suggestions of future outcomes, including statements about: the company's strategy and related milestones and schedules; projections for 2018 and future years and our plans and strategies to realize such projections; belief regarding the temporary nature of financial challenges experienced in the period, and that such challenges do not reflect the company's significant potential for funds flow and earnings growth; the expected mitigating impact on light-heavy crude oil price differentials through the company's downstream integration, pipeline commitments, rail optionality and financial contracts; expected outcomes of the company's hedge positions, including relative to forecast oil production and expected impacts with respect to the company's downside and upside commodity price and light-heavy crude oil differential exposure; expected cost reductions; potential asset divestitures and projected outcomes, including with respect to debt reduction and increasing shareholder value; expected impacts of the company's capacity to slow production through storage in its oil sands reservoirs, including potential to time production and sales at later dates when pipeline capacity and crude oil differentials have improved; expected rail capacity improvements; full-year production volume and steam to oil ratio forecasts; and expected capital costs, including relative to previous estimates.

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 the

forward-looking information is based include: Brent prices of US$55.00/bbl, WTI prices of US$52.00/bbl; WCS of US$37.00/bbl; NYMEX natural gas prices of US$3.00/MMBtu; AECO natural gas prices of $2.20/GJ; Chicago 3-2-1 crack spread of US$15.00/bbl; exchange rate of $0.78 US$/C$ and other assumptions identified in Cenovus’s 2018 guidance (available at cenovus.com); projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; achievement of further cost reductions and sustainability thereof; future improvements in availability of product transportation capacity; increasing share price and market capitalization over the long term; future narrowing of crude oil differentials; realization of expected impacts of the company's capacity to store within its oil sands reservoirs barrels not yet produced, including ability to time production and sales at later dates when pipeline capacity and crude oil differentials have improved; 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; ability to access and implement all technology necessary to achieve expected future results; and other risks and uncertainties described from time to time in the filings the company makes with securities regulatory authorities.

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 or projected and expressed in, or implied by, the forward-looking information. Additional information about the other assumptions and the material risk factors that could cause Cenovus's actual results to differ materially from those expressed or implied by its forward-looking statements is contained under “Risk Management and Risk Factors” and “Forward-looking Information” under “Advisory” in Cenovus’s MD&A for the period ended December 31, 2017 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus'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 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.

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

Exhibit 99.2

wi

Management’s Discussion and Analysis

For the PERIOD ended MARCH 31, 2018

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 April 24, 2018, should be read in conjunction with our March 31, 2018 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2017 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2017 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of April 24, 2018, 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 its 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, 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, 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 8 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 OF 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 March 31, 2018, we had an enterprise value of approximately $23 billion. Operations include oil sands projects in northern Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Our average crude oil and NGLs (collectively, “liquids”) production for the three months ended March 31, 2018 was 395,145 barrels per day, our average natural gas production was 553 MMcf per day, and our total production from continuing operations was 487,464 BOE per day. We also conduct marketing activities and have refining operations in the United States (“U.S.”). The refining operations processed an average of 349,000 gross barrels per day of crude oil feedstock into an average of 369,000 gross barrels per day of refined products.

Our strategy is to increase cash flows through disciplined production growth from our industry-leading portfolio of oil sands and Deep Basin natural gas and liquids assets in western Canada. We are focused on increasing our current share price and maximizing shareholder value through cost leadership and realizing the best margins for our products to help us maintain financial resilience and deliver sustainable dividend growth. We plan to achieve our strategy by drawing on the expertise of our people and leveraging our premium asset quality, executional excellence, value-added integration, focused innovation and trusted reputation.

Our Operations

Oil Sands

Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northern Alberta, including Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake are producing, while Narrows Lake is in the initial stages of development. These three projects are located in the Athabasca region of northeastern Alberta and our project at Telephone Lake is located within the Borealis region of northeastern Alberta. The Oil Sands segment also includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.

Deep Basin

Our Deep Basin operations include liquids rich natural gas, condensate and other NGLs, and light and medium oil assets located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and Alberta, and include interests in numerous natural gas processing facilities (collectively, the “Deep Basin Assets”). The Deep Basin Assets provide short‑cycle development opportunities with high return potential that complement our long-term oil sands development. A portion of the natural gas produced is used as fuel in our oil sands operations and provides an economic hedge for the natural gas required as a fuel source at our refining operations.

Refining and Marketing

Our operations include two refineries located in Illinois and Texas that are jointly owned with (50 percent interest) and operated by Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River and Borger refineries (the “Refineries”) is approximately 314,000 barrels per day and 146,000 barrels per day, respectively. This includes processing capability of up to 255,000 gross barrels per day of blended heavy crude oil. The refining operations allow us to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American light/heavy crude oil price differential fluctuations.

This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and the marketing of third-party purchases and sales of product undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.

Operating Margin Net of Related Capital Investment

QUARTERLY HIGHLIGHTS

In the first quarter of 2018, we:

OPERATING RESULTS

Total production of 488,561 BOE per day increased relative to the first quarter of 2017 primarily due to the Acquisition, offset by the disposition of our legacy Conventional assets late in the second half of 2017. In addition, production at our oil sands facilities was impacted by the decision to reduce production and leave barrels not yet produced in our reservoirs in February and March due to pipeline capacity constraints and wider light-heavy oil price differentials.

Production Volumes

Oil Sands production averaged 359,666 barrels per day in the quarter, a significant increase compared with last year, primarily due to the Acquisition.

Total production from the Deep Basin Assets, acquired on May 17, 2017, averaged 127,056 BOE per day in the first quarter of 2018, with 17 horizontal wells being brought on production.

Production in 2018 from our Conventional segment reflects the results of our Suffield operations, which were sold on January 5, 2018. All references to our legacy Conventional segment are accounted for as a discontinued operation.

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 decreased relative to the first quarter of 2017 primarily due to the impact of materially wider light-heavy crude oil price differentials, higher condensate costs, lower natural gas prices and realized risk management losses as a result of crude prices exceeding our contract prices. WCS as a percentage of WTI was 61 percent in 2018 compared with 72 percent in the same period of 2017, reflecting a decrease in heavy crude oil sales price realizations relative to WTI benchmark pricing. In addition, as the cost of condensate increases relative to the price of blended crude oil, our bitumen sales price decreases. Our average sales price was also effected by the strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact on our sales price of approximately $1.54 per BOE. The impact of higher royalties, and transportation and blending costs were offset by the decline in operating costs.

Refining and Marketing

Crude oil runs and refined product output in the first three months of 2018 decreased compared with 2017. In the first quarter of 2018, major planned turnarounds were substantially completed at both the Wood River and Borger refineries. In the first quarter of 2017, the Refineries were impacted by smaller-scale planned turnarounds.

In 2018, Operating Margin from our Refining and Marketing segment decreased relative to the first quarter of 2017 as higher operating costs and lower crude utilization due to the planned turnarounds at both refineries offset higher average market crack spreads and wider light-heavy crude oil differentials, which decreases input costs to the Refineries.

Further information on the changes in our production volumes, 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 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.

Selected Benchmark Prices and Exchange Rates ⁽¹⁾

Crude Oil Benchmarks

The average Brent, WTI and WCS benchmark prices improved in the first quarter of 2018 compared with the first three months of 2017. Compliance with the production cuts, as outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) and Russia, led to widespread market expectations of an accelerated return to normal inventory levels despite the potential for additional U.S. supply from the Permian basin to offset reduced production.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. In the first quarter of 2018, WTI benchmark prices weakened relative to Brent compared with 2017 as refineries in the U.S. midcontinent were unable to clear the crude oil inventory that accumulated subsequent to Hurricane Harvey and a series of planned turnarounds across the refining industry.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential widened significantly in the first three months of 2018 to levels not seen since the fourth quarter of 2013. WCS weakened relative to WTI due to increasing production in Alberta and limited pipeline capacity. Pipeline outages in the fourth quarter of 2017 forced additional volumes into storage and caused differentials to widen further. In addition, the oil and gas industry has been challenged in securing rail capacity to alleviate pipeline apportionment that has increased short-term pressure on differentials.

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 prices were stronger relative to WTI in the first three months of 2018 compared with 2017 due to incremental demand for diluent as a result of increasing Alberta heavy oil production and minimal spare capacity on pipelines that increased the cost of transporting condensate to Edmonton.

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 improved in the first quarter of 2018 compared with 2017, consistent with the general increase 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 crack spread. The 3‑2‑1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis.

Average Chicago refined product prices increased in the first quarter of 2018 primarily due to higher crude oil prices and wider Chicago 3-2-1 crack spreads. The widening of the Chicago 3-2-1 crack spreads was due to Hurricane Harvey and significant regional refinery maintenance, which caused a wider Brent-WTI differential. 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 weakened compared with the first quarter of 2017 due to higher natural gas supply in Alberta, reduced export capabilities, and extensive pipeline and compressor station maintenance that decreased deliverability to storage facilities. Average NYMEX prices also decreased compared with the first quarter of 2017 as the market continues to expect higher supply.

Foreign Exchange Benchmark

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGL’s, 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.

In the first quarter of 2018, the Canadian dollar relative to the U.S. dollar strengthened compared with the first three months of 2017, which had a negative impact of approximately $213 million on our revenues, excluding our Conventional segment. The Canadian dollar as at March 31, 2018 compared with December 31, 2017 was weaker relative to the U.S. dollar, resulting in $267 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt.

FINANCIAL RESULTS

Selected Consolidated Financial Results

The impact of the Acquisition, condensate prices rising, realized risk management losses and significantly wider light-heavy crude oil price differentials were the primary drivers of our financial results in the three months ended March 31, 2018. The following key performance measures are discussed in more detail within this MD&A.

Revenues

Upstream revenues from continuing operations increased significantly in the first quarter of 2018 compared with 2017. The rise was primarily related to incremental sales volumes as a result of the Acquisition, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar, lower average realized pricing consistent with the materially wider discount in heavy crude oil pricing, and higher royalties.

Refining and Marketing revenues decreased 14 percent compared with the first quarter of 2017. Refining revenues increased primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices, partially offset by lower crude utilization associated with the major planned turnarounds in 2018. Revenues from third‑party crude oil and natural gas sales undertaken by our marketing group decreased significantly in the first quarter of 2018 compared with 2017 due to a decline in crude oil and natural gas volumes sold, as well as lower natural gas prices, partially offset by higher crude oil prices.

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

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

Operating Margin

Operating Margin is an additional subtotal found in Notes 1 and 8 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, 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.

These decreases in Operating Margin from continuing operations were partially offset by increased sales volumes as a result of the Acquisition.

Operating Margin From Continuing Operations Variance

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

Cash From Operating Activities and Adjusted Funds Flow

Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry 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 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 current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding.

Total Cash From Operating Activities and Adjusted Funds Flow

Cash From Operating Activities and Adjusted Funds Flow decreased compared with the first quarter of 2017 due to lower Operating Margin, as discussed above, and an increase in general and administrative costs primarily due to a non-cash expense of $59 million incurred in connection with certain Calgary office space in excess of Cenovus’s current and near-term requirements, and $43 million related to severance costs in the quarter.

The change in non-cash working capital in the first quarter of 2018 was primarily due to a decrease in accounts payable and income tax payable, partially offset by a decrease in accounts receivable. For the three months ended March 31, 2017, the change in non-cash working capital was primarily due to a decline in accounts receivable, partially offset by a decrease 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, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.

Operating Earnings from continuing operations decreased in the first quarter of 2018 compared with 2017 primarily due to lower cash from operating activities and Adjusted Funds Flow, as discussed above, an increase in DD&A which included an impairment of $100 million, a re-measurement loss of $117 million on the contingent payment, a non-cash expense of $59 million incurred in connection with certain Calgary office space in excess of Cenovus’s current and near-term requirements, and unrealized foreign exchange losses on operating items compared with gains in 2017.

Net Earnings (Loss)

In the first quarter of 2018, we incurred a net loss from continuing operations due to:

Net Earnings from discontinued operations for the three months ended March 31, 2018 was $260 million (2017 –  $nil), including a before-tax gain of $348 million on the divestiture of the Suffield asset.

Net Capital Investment

Capital investment in continuing operations in the first quarter of 2018 increased $297 million compared with the first quarter of 2017, reflecting our increased ownership in FCCL and the new asset base in the Deep Basin as a result of the Acquisition. Oil Sands capital investment focused on sustaining capital related to existing production; stratigraphic test wells to determine pad placement for sustaining wells; and the Christina Lake phase G expansion. Capital investment in the Deep Basin focused on all three operating areas and included the drilling of 14 horizontal production wells targeting liquids rich natural gas, as well as capital invested in facilities and infrastructure to support production growth.

Refining and Marketing capital investment increased $7 million in the first quarter of 2018 due to increased capital maintenance and reliability work compared with the same period in 2017.

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

Capital Investment Decisions

We continue to focus on deleveraging our balance sheet. To achieve this, we are currently marketing for sale certain non-core Deep Basin Assets and are continuing to look for opportunities to further streamline our portfolio. In addition to our commitment to continue reducing our debt, we are actively identifying further cost reduction opportunities.

Once our balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner:

Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information.

We expect our capital investment and cash dividends for 2018 to be funded from our internally generated cash flows and our cash balance on hand.

REPORTABLE SEGMENTS

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, 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.

In the second quarter of 2017, Cenovus announced its intention to divest of its Conventional segment that included its heavy oil assets at Pelican Lake, the CO₂ enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were reclassified as held for sale and the results of operations reported as a discontinued operation. As at January 5, 2018, all of the Conventional segment assets were sold. Refer to the Discontinued Operations section of this MD&A for more information.

Revenues by Reportable Segment

OIL SANDS

In northeastern Alberta, we own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects following the completion of the Acquisition. In addition, we have several emerging projects in the early stages of development. The Oil Sands segment includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.

Significant developments in our Oil Sands segment for the first quarter of 2018 compared with 2017 include:

Oil Sands – Crude Oil

Financial Results

Capital investment in excess of Operating Margin from Oil Sands was funded through cash on our balance sheet.

Operating Margin Variance

Revenues

Price

In the first quarter of 2018, our average crude oil sales price decreased to $34.27 per barrel (2017 – $38.08 per barrel). The decrease in our crude oil price resulted from the widening of the WCS-Condensate and the WCS‑Christina Dilbit Blend (“CDB”) differentials and the strengthening of the Canadian dollar relative to the U.S. dollar. The WCS-CDB differential widened to a discount of US$2.68 per barrel (2017 – discount of US$1.79 per barrel).

Our crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios range between 25 percent and 33 percent. As the cost of condensate increases relative to the price of blended crude oil, our bitumen sales price decreases. Due to high demand for condensate at Edmonton, we also purchase condensate from U.S. markets. As such, our average cost of condensate is generally higher than the Edmonton benchmark price due to transportation between market hubs and transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to when we blend it with our production. In a rising crude

oil price environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a lower price earlier in the year.  

Production Volumes

In the first quarter of 2018, production increased primarily due to the Acquisition. Production was also impacted by our decision to temporarily reduce volumes produced in response to takeaway capacity constraints and wider light‑heavy crude oil price differentials. We have significant capacity to store barrels not yet produced within our oil sands reservoirs, allowing flexibility to produce and sell those barrels at a later date when pipeline capacity improves and crude oil differentials narrow.

Condensate

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with a wider WCS-Condensate differential in the first quarter of 2018, the proportion of the cost of condensate recovered decreased. The total amount of condensate used increased as a result of higher production volumes.

Royalties

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

Royalties at Foster Creek, a post-payout project, are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate
(25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and sales prices. Net profits are a function of sales volumes, sales prices and allowed operating and capital costs.

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

Effective Royalty Rates

Royalties increased $31 million in the first quarter of 2018 compared with 2017. Royalties at both Foster Creek and Christina Lake increased primarily due to increased sales volumes and a higher WTI benchmark price (which determines the royalty rate), partially offset by lower crude oil sales prices.

Expenses

Transportation and Blending

In the first quarter of 2018, transportation and blending costs increased $926 million compared to the first quarter of 2017. Blending costs increased due to a rise in condensate volumes required for our increased production and higher condensate prices. Our condensate costs were higher than the average Edmonton benchmark price, primarily due to the transportation expense associated with moving the condensate between market hubs and to our oil sands projects. Transportation costs increased primarily due to incremental sales volumes as a result of the Acquisition.

Per-unit Transportation Expenses

At Foster Creek and Christina Lake, per-barrel transportation costs increased as a result of higher transportation and storage costs, as well as costs associated with transporting additional volumes in the quarter.  

Operating

Primary drivers of our operating expenses in the first quarter of 2018 were workforce costs, fuel, chemical costs, repairs and maintenance and workovers. While per-barrel operating costs decreased two percent, total operating expenses increased $153 million primarily due to the Acquisition, higher chemical costs, and additional repairs and maintenance.

Per-unit Operating Expenses

At Foster Creek, per-barrel fuel costs decreased due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses increased in the first quarter of 2018 primarily due to a true‑up of the emissions charges under the Specified Gas Emitters Regulation (“SGER”) being recognized in the first quarter of 2017, higher chemical costs and increased repairs and maintenance, partially offset by higher sales volumes.

At Christina Lake, fuel costs declined on a per-barrel basis due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses decreased primarily due to higher sales volumes and a true‑up of the emissions charges under the SGER being recognized in the first quarter of 2017. These decreases were partially offset by increased chemical costs associated with the phase F expansion, as well as higher repairs and maintenance activities.

Netbacks ⁽¹⁾

Risk Management

Risk management activities in the first quarter of 2018 resulted in realized losses of $454 million (2017 – realized losses of $77 million), consistent with average benchmark prices exceeding our contract prices.

Oil Sands – Natural Gas

Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production in the first quarter of 2018, net of internal usage, was 4 MMcf per day (2017 – 15 MMcf per day).

Oil Sands – Capital Investment