Company generates $2.5 billion of free funds flow; reduces net debt
Cenovus’s Foster Creek project in northern Alberta
Wolf Lake natural gas plant
CALGARY, Alberta, Feb. 12, 2020 (GLOBE NEWSWIRE) — Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) continued to gain momentum in 2019, generating free funds flow of $361 million in the fourth quarter and approximately $2.5 billion for the year, reducing net debt by 22% year-over-year and completing construction on its Christina Lake phase G oil sands expansion in March. In the fourth quarter of 2019, Cenovus increased its dividend by 25% and reached full ramp-up of its crude-by-rail shipping capacity.
“We continued to deliver on our commitments to shareholders last year,” said Alex Pourbaix, Cenovus President & Chief Executive Officer. “While running safe and reliable operations, we maintained our industry-leading low cost structure, exercised capital discipline and enhanced shareholder value. And through increased rail capacity, we further improved our market access position, providing greater exposure to global oil pricing.”
Key fourth-quarter and 2019 developments
- Reduced net debt by a further $289 million to $6.5 billion in the fourth quarter
- Generated cash from operating activities of $740 million in the fourth quarter and $3.3 billion for the full year as well as adjusted funds flow of $678 million in the fourth quarter and $3.7 billion for the full year
- Reduced year-over-year upstream operating expenses through focused cost leadership
- Exceeded crude-by-rail shipping target, achieving 106,000 barrels per day (bbls/d) loaded in December
- Achieved fourth-quarter oil sands production of more than 374,000 bbls/d, up from 355,000 bbls/d in the third quarter of 2019 mainly due to reduced curtailment levels
|2019 production & financial summary1|
|(for the period ended December 31)||2019
|Financial ($ millions, except per share amounts)|
|Cash from operating activities||740||485||53||3,285||2,154||53|
|Adjusted funds flow2||678||-36||3,724||1,674||122|
|Per share diluted||0.55||-0.03||3.03||1.36|
|Free funds flow2||361||-312||2,548||311||719|
|Operating earnings (loss) from continuing operations2||-164||-1,670||456||-2,755|
|Per share diluted||-0.13||-1.36||0.37||-2.24|
|Net earnings (loss) from continuing operations||113||-1,350||2,194||-2,916|
|Per share diluted||0.09||-1.10||1.78||-2.37|
|Production (from continuing operations)3
|Oil sands (bbls/d)||374,132||326,481||15||354,257||362,996||-2|
|Deep Basin liquids3 (bbls/d)||26,197||28,111||-7||26,673||32,454||-18|
|Total liquids production from
continuing operations3 (bbls/d)
|Total natural gas (MMcf/d)||403||469||-14||424||528||-20|
|Total production from continuing operations (BOE/d)||467,448||432,713||8||451,680||483,458||-7|
1 Cenovus adopted IFRS 16, “Leases,” effective January 1, 2019; see full note in the Advisory.
2 Adjusted funds flow, free funds flow and operating earnings/loss are non-GAAP measures. See Advisory.
3 Includes oil and natural gas liquids (NGLs).
In 2019, Cenovus increased cash from operating activities to approximately $3.3 billion from $2.2 billion the previous year and adjusted funds flow to about $3.7 billion from $1.7 billion in 2018. Cenovus had free funds flow of approximately $2.5 billion in 2019, an eight-fold increase from a year earlier, driven by higher adjusted funds flow and disciplined capital spending. Fourth-quarter free funds flow was $361 million compared with a shortfall of $312 million in the same period of 2018.
The company’s full-year upstream results benefited from a 52% narrowing of the differential between West Texas Intermediate (WTI) and Western Canadian Select (WCS) crude oil prices in 2019 compared with 2018 as well as increased sales at locations outside of Alberta, where the company was able to achieve higher realized prices. Refining margins were lower compared with 2018 primarily due to reduced realized crack spreads.
“With our low cost structure, continued focus on capital discipline and our diversified transportation portfolio to get more of our product to U.S. markets, we were able to generate very strong free funds flow in 2019,” said Pourbaix. “And we put that cash to good use, further deleveraging our balance sheet and increasing our dividend in the fourth quarter of the year.”
Operating earnings from continuing operations were $456 million in 2019, compared with an operating loss from continuing operations of nearly $2.8 billion in 2018. The year-ago results included a significant realized hedging loss, as well as a number of significant non-cash items. Full-year 2019 net earnings from continuing operations were approximately $2.2 billion compared with a net loss from continuing operations of $2.9 billion a year earlier. The year-over-year increase in net earnings was driven by higher operating earnings relative to 2018, non-operating foreign exchange gains of $787 million in 2019 compared with losses of $593 million in 2018 and a deferred income tax recovery in 2019, including $671 million related to the reduction of Alberta’s corporate income tax rate and $387 million due to an internal restructuring of the company’s U.S. operations resulting in an increased tax basis of its U.S. refining assets.
Further information on the company’s financial results are included in its 2019 Management Discussion & Analysis (MD&A) available in the Investors section at cenovus.com.
Balance sheet strength and capital discipline
Cenovus continued to make significant progress on its deleveraging plans through the past year, repaying approximately US$1.8 billion of its unsecured notes and reducing net debt to $6.5 billion by year end, compared with net debt of approximately $8.4 billion at the start of 2019. Cenovus’s net debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) ratio was 1.6 times at the end of 2019, down from 1.9 times at the end of the third quarter and 5.9 times at the end of 2018. Deleveraging remains a top priority for Cenovus as the company continues to pursue its net debt target of $5 billion. At net debt of $5 billion, Cenovus anticipates being in a position to maintain a target ratio of less than two times net debt to adjusted EBITDA, at bottom-of-the-cycle commodity prices.
During the fourth quarter of 2019, Moody’s Investors Service affirmed Cenovus’s Ba1 credit rating and improved its outlook from ‘stable’ to ‘positive,’ citing the significant amount of debt reduction the company has achieved. In addition to making progress towards re-establishing an investment grade credit rating at Moody’s, Cenovus remains committed to maintaining its investment grade credit ratings at S&P Global Ratings, DBRS Limited and Fitch Ratings.
Market access and integration
Cenovus successfully ramped up its crude-by-rail shipping capacity in 2019 and in December exceeded its target by achieving average rail loading volumes of nearly 106,000 bbls/d.
While pipelines remain the cornerstone of Cenovus’s transportation strategy, rail continues to be an important option to bridge the gap until expansion pipelines are completed. Pipelines and rail are part of the company’s integrated business model designed to maximize exposure to global oil prices and mitigate pipeline congestion through a range of options to increase margins and reduce cash flow volatility.
Cenovus’s 2019 oil sands production averaged 354,257 bbls/d, approximately 2% lower than in 2018 primarily due to the Government of Alberta’s mandated curtailment program. Fourth-quarter oil sands volumes averaged 374,132 bbls/d, 15% higher than the same quarter in 2018. In December 2019, the Alberta government introduced the Special Production Allowance (SPA) program, which allows crude oil producers to exceed mandated curtailment levels if those volumes are transported using incremental crude-by-rail capacity. In the fourth quarter of 2018, volumes were impacted by Cenovus’s voluntary decision to restrict oil sands production rates in response to pipeline constraints and wide light-heavy oil differentials. Cenovus anticipates higher oil production levels overall this year compared with 2019 due to the return to unconstrained production with the SPA program and the ramp-up of Christina Lake phase G over the next six to 12 months.
“While mandatory curtailment reduced our overall production volumes in 2019, it helped keep light-heavy oil price differentials from reaching the record highs we saw at the end of 2018, contributing to a significant overall benefit for the province and for our industry,” said Pourbaix. “Compared with 2018, our royalty payments to the province of Alberta increased significantly, more than doubling to $1.1 billion in 2019.”
Cenovus continues to deliver equally strong operational, financial and environmental, social and governance (ESG) performance with a continued focus on being an ESG leader within its industry. In January, Cenovus announced its four ESG focus areas and set bold targets to guide its performance related to climate and greenhouse gas (GHG) emissions, Indigenous engagement, land and wildlife and water stewardship. The company also announced last month it plans to invest $10 million per year for at least five years to build much-needed new homes in six Indigenous communities near Cenovus’s oil sands operations in northern Alberta.
As part of its commitment to strong ESG performance, Cenovus is committed to rigorous governance practices and industry-leading safety performance. In 2019, the company’s overall health and safety performance improved from the previous year due to Cenovus’s focus on risk management and asset integrity. The company also achieved the second-lowest recordable injury frequency in its history.
Fourth-quarter oil sands production at Cenovus’s Christina Lake and Foster Creek oil sands projects was more than 374,000 bbls/d, up from 355,000 bbls/d in the third quarter of 2019 mainly driven by the easing of mandatory curtailment levels. Full-year 2019 production declined slightly from a year earlier primarily due to curtailment. As a result of the SPA program and increased rail shipping capacity, Cenovus has returned to unconstrained production, and the company expects to ramp up its Christina Lake phase G expansion over the next six to 12 months.
Fourth-quarter oil sands operating costs were $8.06 per barrel (bbl) essentially flat with the same period a year earlier. Full-year oil sands operating costs were $8.15/bbl, up 7% from $7.65/bbl in 2018 primarily due to lower volumes as a result of mandated curtailment. Per-barrel oil sands operating costs also increased as a result of higher repairs and maintenance activity and related costs due to a turnaround at Christina Lake during the second quarter, and higher fuel costs. Fuel costs increased year over year due to higher natural gas prices and fuel consumption as Cenovus maintained normal steam injection rates at its oil sands operations while reducing production volumes to meet mandated curtailment levels. Cenovus continued to achieve further reductions in its oil sands sustaining capital costs in 2019, which declined 10% to $567 million, or approximately $4.00 per barrel of capacity from the previous year.
At Christina Lake, the steam to oil ratio (SOR) was 2.0 in 2019, compared with 1.9 in 2018. At Foster Creek, the SOR was unchanged at 2.8 from a year earlier.
Full-year 2019 oil sands operating margin increased more than three-fold year over year to approximately $3.5 billion due to higher average realized sales prices, decreased transportation and blending costs and realized risk management losses of $23 million compared with losses of approximately $1.6 billion in 2018, partially offset by lower sales volumes and higher royalties.
Cenovus has largely completed work to optimize its Deep Basin operating model to reduce costs, improve efficiency and maximize value. The company continues to take a disciplined approach in the Deep Basin and is driving the business to be resilient at bottom-of-the-cycle commodity prices of US$45/bbl WTI and Alberta Energy Company (AECO) pricing of $1.50 per gigajoule. The Deep Basin generated operating margin in excess of capital investment of $64 million in the fourth quarter of 2019, up 45% from the same period a year earlier. Operating margin in excess of capital investment was $189 million for the full year.
Deep Basin production averaged 97,423 barrels of oil equivalent per day (BOE/d) in 2019, a 19% decrease from 2018 levels, due to natural declines from lower sustaining capital investment, the divestiture of Cenovus’s Pipestone Partnership in 2018 and temporary well shut-ins in response to low natural gas prices.
Total Deep Basin operating costs decreased 16% in 2019 compared with the previous year as a result of the Pipestone divestiture, lower third-party processing costs due to lower throughput and Cenovus focusing on optimizing operations. This optimization work included well interventions, repair and maintenance activities and leveraging the company’s processing infrastructure to lower the cost structure. Despite the 2019 year-over-year production decrease on a full-year basis, operating costs increased a modest 2% to $8.79/BOE from $8.58/BOE in 2018.
Refining and marketing
Cenovus’s Wood River, Illinois and Borger, Texas refineries, which are co-owned with the operator, Phillips 66, had solid operational performance in 2019. Crude oil runs and refined product output in 2019 were consistent with the previous year.
Refining and marketing operating margin for the fourth quarter was $109 million, compared with $251 million in the same quarter of 2018. Full-year refining and marketing operating margin was $737 million, compared with operating margin of $996 million in the year-earlier period. The year-over-year decrease was primarily due to reduced crude cost advantage as heavy and medium sour crude oil differentials narrowed.
Effective January 2020, the Wood River refinery was re-rated to reflect higher processing capacity of 346,000 gross bbls/d, an increase of 13,000 bbls/d from 2019.
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 $140 million lower in 2019, compared with $118 million higher in 2018.
Cenovus’s proved and probable reserves are evaluated each year by independent qualified reserves evaluators (IQREs). At the end of 2019, Cenovus had total proved reserves of approximately 5.1 billion BOE, essentially unchanged from 2018, while total proved plus probable reserves decreased 2% to about 6.9 billion BOE. Proved bitumen reserves were approximately 4.8 billion barrels, while proved plus probable bitumen reserves were about 6.4 billion barrels, both relatively unchanged from 2018. Cenovus’s reserve life index (RLI) for proved reserves is in excess of 30 years, with proved plus probable reserves having an RLI in excess of 40 years.
Cenovus’s 2019 proved reserves finding and development (F&D) costs were $7.57/BOE, excluding changes in future development costs, up 74% from 2018, reflecting lower proved reserves additions, partially offset by decreased capital spending. Three-year average proved reserves F&D costs were $5.97/BOE, excluding changes in future development costs.
Cenovus, which primarily holds long-life bitumen reserves, believes another meaningful measure of efficiency is F&D costs for proved developed reserves, excluding changes in future development costs. For 2019, Cenovus’s bitumen proved developed reserves F&D costs were $2.49/bbl, excluding changes in future development costs, a decrease of more than 50% from 2018, mainly as a result of lower capital expenditure on Christina Lake phase G, deferral of oil sands sustaining capital expenditure and the company’s focus on maximizing value.
More details about Cenovus’s reserves and other oil and gas information is available in the Advisory, the company’s Annual Information Form (AIF) and Annual Report on Form 40-F for the year ended December 31, 2019, which are available on SEDAR at sedar.com, EDGAR at sec.gov and Cenovus’s website at cenovus.com.
For the first quarter of 2020, the Board of Directors declared a dividend of $0.0625 per share, payable on March 31, 2020 to common shareholders of record as of March 13, 2020. Based on the February 11, 2020 closing share price on the Toronto Stock Exchange of $11.98, this represents an annualized yield of approximately 2.1%. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis.
Year-end disclosure documents
Today, Cenovus is filing its audited Consolidated Financial Statements, MD&A, and AIF with Canadian securities regulatory authorities. The company is also filing its Annual Report on Form 40-F for the year ended December 31, 2019 with the U.S. Securities and Exchange Commission. Copies of these documents will be available today on SEDAR at sedar.com, EDGAR at sec.gov (for the Form 40-F) and the company’s website at cenovus.com under Investors. They can also be requested free of charge by email at email@example.com.
Conference Call Today
9 a.m. Mountain Time (11 a.m. Eastern Time)
Cenovus will host a conference call today, February 12, 2020, starting at 9 a.m. MT (11 a.m. ET). To participate, please dial 888-231-8191 (toll-free in North America) or 647-427-7450 approximately 10 minutes prior to the conference call. A live audio webcast of the conference call will also be available via cenovus.com. The webcast will be archived for approximately 90 days.
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.
Finding and Development Costs
Finding and development (F&D) costs are calculated by dividing the sum of total exploration and development costs incurred in 2019 in respect of the relevant product types by the sum of total additions and revisions for the applicable category of reserves in the same period. The additions and revisions for the applicable category of reserves for the period are determined by Cenovus’s IQREs, effective December 31, 2019, and for purposes of determining F&D costs, exclude changes resulting from acquisitions, dispositions and production. F&D costs provide an indication of the unit cost of finding and developing new reserves. F&D costs do not have a standardized meaning and are defined differently by different companies and as such are not comparable to similar measures presented by other issuers.
Estimates of reserves referenced in this release were prepared effective December 31, 2019 by IQREs, based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Estimates are presented using an average of the January 1, 2020 price forecasts from three IQREs. For additional information about our reserves and other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in Cenovus’s AIF and Annual Report on Form 40-F for the year ended December 31, 2019 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus’s website at cenovus.com).
Cenovus adopted International Financial Reporting Standard 16, “Leases,” effective January 1, 2019 using the modified retrospective approach; therefore, 2018 comparative information has not been restated.
Non-GAAP Measures and Additional Subtotal
This news release contains references to adjusted EBITDA, adjusted funds flow, cash flow, capitalization, free funds flow, operating earnings (loss) and net debt, which are non-GAAP measures, and operating margin, which is an additional subtotal found in Notes 1 and 11 of Cenovus’s Audited Consolidated Financial Statements for the year ended December 31, 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 December 31, 2019 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus’s website at cenovus.com).
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”, “committed”, “continue”, “driving”, “expect”, “focus”, “plan”, “target” and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to statements about: maintaining a target ratio of less than two times Net Debt to adjusted EBITDA at bottom-of-the-cycle commodity prices; maintaining investment grade credit ratings; maximizing exposure to global oil prices and mitigating pipeline congestion through a range of options to increase margins and reduce cash flow volatility; future oil production in 2020, including returning to unconstrained production; Cenovus’s four ESG focus areas and related targets and ambitions; plans to invest $10 million per year for at least five years in six Indigenous communities; the ramp-up of the Christina Lake phase G expansion over the next six to 12 months; achieving resilience in the Deep Basin at commodity prices of US$45/bbl WTI and AECO pricing of $1.50 per gigajoule; and all statements related to the company’s updated 2020 Guidance (dated December 9, 2019).
Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which our forward-looking information is based include, but are not limited to: forecast oil and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials and other assumptions identified in Cenovus’s 2020 guidance (dated December 9, 2019), available at cenovus.com; bottom-of-the-cycle commodity prices of about US$45/bbl WTI and C$44/bbl WCS; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to our share price and market capitalization over the long term; future narrowing of crude oil differentials; the Government of Alberta’s mandatory production curtailment continuing to maintain a relatively narrow differential between WTI and WCS crude oil prices thereby positively impacting cash flows for Cenovus; the ability of our refining capacity, dynamic storage, existing pipeline commitments, financial hedge transactions and plans to ramp up crude-by-rail loading capacity to partially mitigate a portion of our WCS crude oil volumes against wider differentials; ability to produce from our oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgments; results; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects, development programs or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the availability of Indigenous owned or operated businesses; our ability to develop, access and implement all technology and equipment necessary to achieve expected future results, and that such results are realized.
2020 guidance, dated December 9, 2019, assumes: Brent prices of US$60.00/bbl, WTI prices of US$55.00/bbl; WCS of US$37.50/bbl; AECO natural gas prices of $1.80/Mcf; Chicago 3-2-1 crack spread of US$16.00/bbl; and an exchange rate of $0.76 US$/C$.
The risk factors and uncertainties that could cause our actual results to differ materially, include, but are not limited to: our ability to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; failure of the Government of Alberta’s mandatory production curtailment to continue to cause the differential between the WTI and the WCS crude oil prices to narrow or to narrow sufficiently to positively impact our cash flows; unexpected consequences related to the Government of Alberta’s mandatory production curtailment; the effectiveness of our risk management program; the accuracy of cost estimates regarding commodity prices, currency and interest rates; product supply and demand; accuracy of our share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks, exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; our ability to maintain desirable ratios of net debt to adjusted EBITDA as well as net debt to Capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; accuracy of our reserves, future production and future net revenue estimates; accuracy of our accounting estimates and judgements; our ability to replace and expand oil and gas reserves; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of our assets or goodwill from time to time; our ability to maintain our relationship with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; ability to successfully complete development programs; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; cost escalations; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation and litigation related thereto; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to our business, including potential cyberattacks; risks associated with climate change and our assumptions relating thereto; the timing and the costs of well and pipeline construction; our ability to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; possible failure to obtain and retain qualified staff and equipment in a timely and cost efficient manner; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; changes in general economic, market and business conditions; the political and economic conditions in the countries in which we operate or supply; the occurrence of unexpected events and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against us.
Statements relating to “reserves” are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of Cenovus’s material risk factors, refer to “Risk Management and Risk Factors” in the Corporation’s annual 2019 MD&A, which section of the MD&A is incorporated by reference into this AIF, and to the risk factors described in other documents Cenovus files from time to time with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Corporation’s website at cenovus.com.
Cenovus Energy Inc.
Cenovus Energy Inc. is a Canadian integrated oil and natural gas company. It is committed to maximizing value by sustainably developing its assets in a safe, innovative and cost-efficient manner, integrating environmental, social and governance considerations into its business plans. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and British Columbia. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. For more information, visit cenovus.com.
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