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 October 2020 |
|
Commission File Number: 1-34513 |
CENOVUS ENERGY INC.
(Translation of registrant’s name into English)
4100, 225 - 6 Avenue S.W.
Calgary, Alberta, Canada T2P 1N2
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☒
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐
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. 333-233702).
DOCUMENTS FILED AS PART OF THIS FORM 6-K
See the Exhibit Index to this Form 6-K.
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: October 29, 2020
|
|
|
CENOVUS ENERGY INC. |
|
|
|
|
|
(Registrant) |
|
|
|
|
By: |
|
/s/ Elizabeth A. McNamara |
|
|
||
|
|
|
|
Name: |
|
Elizabeth A. McNamara |
|
|
|
|
|
|
Title: |
|
Assistant Corporate Secretary |
|
|
Exhibit No. |
|
|
|
|
|
99.1 |
|
News Release dated October 29, 2020 |
|
|
|
99.2 |
|
Management’s Discussion and Analysis dated October 28, 2020 for the period ended September 30, 2020 |
|
|
|
99.3 |
|
Interim Consolidated Financial Statements (unaudited) for the period ended September 30, 2020 |
|
|
|
99.4 |
|
Supplemental Financial Information (unaudited) – Consolidated Interest Coverage Ratios Exhibit to September 30, 2020 Interim Consolidated Financial Statements |
|
|
|
99.5 |
|
Form 52-109F2 Full Certificate, dated October 29, 2020, of Alex J. Pourbaix, President & Chief Executive Officer |
|
|
|
99.6 |
|
Form 52-109F2 Full Certificate, dated October 29, 2020, of Jonathan M. McKenzie, Executive Vice-President & Chief Financial Officer |
|
|
|
101 |
|
Interactive data file |
|
|
|
Exhibit 99.1
Cenovus delivers strong third-quarter operating results
Company generates free funds flow, reduces net debt
Calgary, Alberta (October 29, 2020) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) continued to deliver strong operational performance and further improved its financial resilience in the third quarter by remaining committed to disciplined capital investment, cost leadership and leveraging the flexibility of its assets and marketing strategy to generate positive free funds flow. The company took advantage of the higher commodity prices by ramping up production from its oil sands assets and selling barrels stored in the preceding quarter. Higher crude oil prices and increased sales volumes allowed the company to achieve free funds flow for the third quarter of $266 million, which contributed to a reduction in net debt to $7.5 billion at the end of the period.
“The third quarter clearly demonstrated the strength and reliability of our operations and our ability to effectively manage production and sales by storing barrels when prices declined and then capitalizing on a price recovery to optimize returns,” said Alex Pourbaix, Cenovus President & Chief Executive Officer. “We continue to find ways to optimize our cost structure, expand our market access, and strengthen the balance sheet. We believe the proposed transaction with Husky Energy, announced earlier this week, will address these priorities, positioning us to come through this period more resilient, with increased and stable free funds flow, supporting accelerated deleveraging and returns to shareholders.”
Cenovus Husky transaction
Cenovus’s planned transaction with Husky Energy Inc. will create a resilient integrated Canadian energy leader with an advantaged upstream and downstream portfolio that is expected to provide enhanced free funds flow generation and superior return opportunities for investors.
The companies are advancing the arrangement process, with regulatory filings being prepared and filed. The Joint Management Information Circular is being prepared for expected distribution by mid-November and key members of the combined integration teams have been identified.
“Teams from both Cenovus and Husky are moving the process along so that we can be in a position to implement the vision of the new company as soon as possible,” said Pourbaix, who will lead the combined entity as President & Chief Executive Officer following a closing anticipated in the first quarter of 2021. “We’re very excited about the opportunities that the combination of our two companies creates for all of our stakeholders.”
Business flexibility and financial discipline
In the third quarter of 2020, Cenovus increased crude oil production at its oil sands facilities and overall sales in response to higher commodity prices while remaining focused on maintaining its low operating and capital cost structure and deleveraging its balance sheet. The company was able to use the flexibility of its oil sands assets and available production curtailment credits to increase output above the Alberta government’s mandatory limits. Cenovus achieved average oil sands production of almost 386,000 barrels per day (bbls/d) in the third quarter, up from 373,000 bbls/d in the previous quarter and a 9% increase from the same period a year earlier.
The company also employed its suite of transportation and storage assets to capture increased value from the higher prices. During the quarter, Cenovus sold crude oil inventory built up from April to June when crude oil prices were significantly lower. The average benchmark price for Western Canadian Select (WCS) crude oil almost doubled to $42.41 per barrel (bbl) in the third quarter from $22.42/bbl in the second quarter of 2020 and significantly higher than the April benchmark price of $4.92/bbl.
These actions combined with continued capital spending and operating cost discipline contributed to significantly improved financial performance during the third quarter compared with the second quarter of this year. Third quarter capital investment in the company’s oil sands and conventional segments was flat compared with the second quarter of 2020 and approximately 50% lower on a year-over-year basis after the company took decisive action earlier this year to respond to lower commodity prices and the rapid weakening of the business environment.
“Our people in the field have done an excellent job of maintaining strong operating performance even as we reduced capital spending due to the lower price environment and the challenges brought on by COVID-19,” said Pourbaix. “Safe and reliable operations will continue to be a priority, along with a commitment to finding ways of further reducing our overall costs to help us maintain our competitive advantage and remain an attractive long-term investment.”
2
Third-quarter financial results
Cenovus recorded cash from operating activities of $732 million in the third quarter compared with $834 million of cash used in operating activities in the second quarter of 2020. The company generated third-quarter adjusted funds flows of $414 million and free funds flow of $266 million driven by the recovery in benchmark commodity prices, the ramp-up of production in the quarter and increased sales of barrels that were stored in the second quarter and were withdrawn from storage and sold as prices recovered.
The company had a third-quarter operating loss of $452 million and a net loss of $194 million compared with operating earnings of $284 million and net earnings of $187 million in the same period in 2019. The operating loss was due to lower cash from operating activities and adjusted funds flow, and higher depreciation, depletion, and amortization that included an impairment charge of $450 million associated with a refinery Cenovus co-owns with the operator, Phillips 66, at Borger, Texas, partially offset by non-operating realized foreign exchange gains of $30 million. The net loss in the third quarter of this year was due to the operating loss, partially offset by unrealized risk management gains of $135 million, non-operating unrealized foreign exchange gains of $152 million compared with losses of $87 million, and a deferred income tax recovery of $177 million compared with a deferred income tax expense of $46 million in the third quarter of 2019. Overall financial results were negatively impacted compared with the third quarter of 2019 largely due to a one-third decline in benchmark crude oil prices driven by the COVID-19 pandemic.
The impairment charge taken on the Borger refinery reflects current market conditions surrounding reduced demand for refined products, and the expectation of continued lower market crack spreads in the market.
At the end of the third quarter, Cenovus’s net debt declined to approximately $7.5 billion from $8.2 billion at the end of the second quarter of 2020, in part due to directing positive free funds flow towards debt repayment. In July 2020, Cenovus issued US$1.0 billion in 5.375% senior unsecured notes due in 2025 with net proceeds used to repay borrowings on the company’s credit facilities.
Response to COVID-19
Earlier this year, Cenovus responded quickly to the COVID-19 pandemic and in the past several months has implemented special protocols and measures to protect the health and safety of its workforce and to ensure the continuity of its business. With these measures now well established, the company recently lifted its mandatory work from home order that had been in place for most staff since mid-March and is now implementing a gradual return to its Calgary office. Cenovus continues to closely monitor the COVID-19 situation and will not compromise on the health and safety of its workers or on its commitment to safe and reliable operations.
Operating highlights
Cenovus’s upstream and refining assets continued to deliver safe and reliable operational performance during the third quarter. Planned maintenance and repair work in the third quarter partially offset production increases at both of the company’s oil sands operations and contributed to lower output at its conventional properties. The work was deferred from earlier in the year due to reduced staffing at our operations as a result of COVID-19.
3
Health and safety
Cenovus remains focused on delivering industry-leading safety performance through its focus on risk management and asset integrity, delivering very strong results through the first nine months of the year. The company has achieved noteworthy year-over-year improvements in focus areas of Significant Incident Frequency (SIF) and Process Safety Events. The company recorded a Significant Incident Frequency of zero compared with 0.12 in the third quarter of 2019 and no Process Safety Events compared with one in the same period a year earlier. Total Recordable Injury Frequency has largely remained flat compared with the same period in 2019 when Cenovus achieved its best ever performance in this area. These results included significant safety milestones for Drilling Operations as well as Completions and Well Services at our Christina Lake oil sands facility, with both groups achieving one year without a recordable incident during the third quarter. The company’s Conventional operations also continued to deliver strong safety performance, marking a one-year milestone in September since recording a significant process safety event.
Oil sands
For the third quarter, Christina Lake had average production of 220,983 bbls/d, and Foster Creek had average production of 164,954 bbls/d. The company achieved combined oil sands production of 385,937 bbls/d in the third quarter, compared with 354,595 bbls/d in the same period a year earlier. During the third quarter of 2020, Cenovus was able to produce additional barrels of oil, despite curtailment, due to the purchase of low-cost production curtailment credits from other companies.
Oil sands operating margin in the third quarter increased to $638 million from $125 million in the second quarter of 2020 due to higher average realized crude oil sales price and higher sales volumes, partially offset by increased transportation and blending costs and higher royalties. Non-fuel per-unit operating costs in the third quarter declined 5% at Christina Lake and were relatively flat at Foster Creek compared with the same period a year earlier. Overall, third-quarter oil sands per-unit operating costs were $7.53/bbl, up 9% from the same period a year earlier and 2% from the second quarter of 2020. The year-over-year increase in costs was primarily due to higher per-barrel fuel costs as a result of higher natural gas prices, partially offset by increased sales volumes. Transportation costs were lower due to the suspension of the company’s crude-by-rail program in response to unfavourable pricing fundamentals for shipping by rail.
Cenovus’s oil sands facilities continue to operate at industry-leading steam-to-oil ratios (SOR). At Christina Lake, the SOR was 2.1 in the third quarter, in line with both the second quarter of 2020 and the same period a year earlier. The SOR at Foster Creek was 2.7, level with the preceding quarter of 2020 and the third quarter a year earlier.
Conventional
Conventional production averaged approximately 85,862 barrels of oil equivalent per day (BOE/d) in the third quarter, a 9% decrease from the same period in 2019. The year-over-year decrease was due to natural declines from limited capital investment and increased downtime due to a planned turnaround at a non-operated natural gas plant, partially offset by the addition of Marten Hills heavy oil production starting in 2020.
4
Capital investment in the company’s Conventional segment is forecast to range between $75 million and $85 million for full-year 2020. This includes an incremental $30 million of capital investment in the fourth quarter, relative to Deep Basin guidance, for a two-rig drilling program targeting low-risk, high-return development wells near natural gas plants owned and operated by Cenovus to take advantage of an expected strengthening in commodity prices during the winter heating season. We continue to take a disciplined approach to the development of our Conventional assets.
Total conventional operating costs increased 5% to $81 million in the third quarter of 2020 compared with the same period in the previous year and remained flat relative to the second quarter of 2020. Per-barrel operating costs averaged $9.55/BOE compared with $8.21/BOE in the third quarter of 2019 due to lower sales volumes, increased costs for planned repairs and maintenance related to turnaround activities and higher third-party processing fees.
Full-year guidance dated April 1, 2020 is available on our website at cenovus.com.
Refining and marketing
Cenovus’s Wood River, Illinois and Borger refineries, which are co-owned with the operator, Phillips 66, maintained safe and reliable performance in the third quarter of 2020. Crude oil runs at both refineries were reduced in response to the economic slowdown due to COVID-19. Crude runs averaged 382,000 bbls/d in the third quarter, an increase of 18% from the second quarter of 2020 and 18% lower from the same period in 2019.
Cenovus had a refining and marketing operating margin shortfall of $74 million in the third quarter compared with positive operating margin of $126 million in the same period of 2019, primarily due to reduced market crack spreads, lower crude oil runs and crude advantage, partially offset by lower operating costs.
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 $39 million lower in the third quarter, compared with $8 million lower in the same period in 2019.
Sustainability
Cenovus is committed to maintaining world-class safety performance and environmental, social and governance (ESG) leadership, including robust ESG disclosure. The company will continue earning its position as a global energy supplier of choice by advancing clean technology and reducing emissions intensity, including maintaining its ambition of achieving net zero emissions by 2050. Advancing environmental stewardship and maintaining strong local community relationships, with a focus on Indigenous economic reconciliation, will continue to be a priority for the company following the close of the Husky transaction. Leading safety practices, strong governance and advancing diversity and inclusion will remain central to the company’s ESG commitments.
“Striking the right balance among environmental, economic and social considerations is core to our strategy of creating long-term value and business resilience for our company,” said Pourbaix. “We will demonstrate ongoing leadership through our support of local
5
communities, caring for the environment and emissions reduction efforts to support the transition to a low-carbon energy future.”
The targets Cenovus released earlier this year for its key ESG focus areas involved a robust process to ensure alignment with the company’s business plan and strategy. The company remains committed to pursuing meaningful, measurable ESG targets and will undertake a thorough analysis of the most meaningful targets to pursue for its expanded portfolio. Once that work is complete in 2021 and approved by the Board, the new targets and plans to achieve them will be disclosed.
Conference Call Today 9 a.m. Mountain Time (11 a.m. Eastern Time) Cenovus will host a conference call today, October 29, 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. |
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 earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted funds flow, free funds flow, operating earnings (loss) and net debt, which are non-GAAP measures, and operating margin, which is an additional subtotal found in Note 1 of Cenovus's Interim Consolidated Financial Statements for the period ended September 30, 2020 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus's website at cenovus.com). These measures do not have a standardized meaning as prescribed by IFRS. Readers should not consider these measures in isolation or as a substitute for analysis of the company's results as reported under IFRS. These measures are defined differently by different companies and therefore are not comparable to similar measures presented by other issuers. For definitions, as well as reconciliations to GAAP measures, and more information on these and other non-GAAP
6
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 September 30, 2020 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus's website at cenovus.com).
Forward-looking Information
This news release contains certain forward-looking statements and forward-looking
information (collectively referred to as “forward-looking information”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although Cenovus believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking information as actual results may differ materially from those expressed or implied.
Forward-looking information in this document is identified by words such as “achieve”, “advance”, “aim”, “ambition”, “anticipate”, “believe”, “commitment”, “continue”, “contribute”, “development”, “drive”, “ensure”, “expect”, “focus”, “forecast”, “goal”, “guidance”, “maintain”, “opportunity”, “plan”, “position”, “potential”, “priority”, “protect”, “realize”, “target” and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our expectations regarding the volatility of commodity prices and our ability to withstand an extended period of low oil prices; the timing of distribution of the Joint Management Information Circular and completion of the plan of arrangement with Husky Energy Inc. (the “Husky Transaction”); the timing and anticipated receipt of required regulatory, court and securityholder approvals for the Husky Transaction and other customary closing conditions; anticipated benefits of the Husky Transaction; our ability to generate shareholder returns; the robust performance of our assets; finding ways to further reduce our overall costs; maintaining our low operating and capital cost structure and deleveraging our balance sheet to maintain our competitive advantage and remain an attractive investment; maintaining our priority of safe and reliable operations; delivering industry-leading safety performance through our focus on risk management and asset integrity; maintaining world-class ESG leadership and disclosure; maintaining our ambition of achieving net zero emissions by 2050; disclosing new ESG targets and priorities and plans to achieve them for our expanded portfolio; monitoring the COVID-19 situation and not compromising the health and safety of our workers; forecast capital investment in our Conventional segment; and maintaining a disciplined approach to development of our Conventional segment.
Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which our forward-looking information is based include, but are not limited to: forecast oil and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials and other assumptions identified in Cenovus’s 2020 guidance (dated April 1, 2020), available at cenovus.com; the satisfaction of the conditions to closing of the Husky Transaction in a timely manner and complete the arrangement on the expected terms; the
7
combined company's ability to successfully integrate the businesses of Cenovus and Husky; access to sufficient capital to pursue any development plans associated with full ownership of Husky; the combined company's ability to issue securities; the impacts the Husky Transaction may have on the current credit ratings of Cenovus and Husky and the credit rating of the combined company following closing; our ability to achieve our ambition of net zero emissions by 2050; our ability to set new ESG targets for our expanded portfolio; global demand for refined products will resume and prices will rise; continued access to short-term capital such as credit and demand facilities; continued impact of measures implemented to enhance the company’s resilience; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to our share price and market capitalization over the long term; future or continued narrowing of crude oil differentials; the ability of our refining capacity, dynamic storage, existing pipeline commitments and financial hedge transactions to partially mitigate a portion of our WCS crude oil volumes against wider differentials; our ability to adjust production while maintaining reservoir integrity; availability of new ways to get our products to new customers; opportunities to work with industry partners to find innovative market-based solutions aimed at refining more Canadian oil in Canada; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgments; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects, development programs or stages thereof; our ability to generate sufficient liquidity to meet our current and future obligations; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to develop, access and implement all technology and equipment necessary to achieve expected future results, and that such results are realized.
2020 guidance, dated April 1, 2020, assumes: Brent prices of US$39.00/bbl, WTI prices of US$34.00/bbl; WCS prices of US$18.50/bbl; Differential WTI-WCS of US$15.50/bbl; AECO natural gas prices of $2.00/Mcf; Chicago 3-2-1 crack spread of US$8.30/bbl; and an exchange rate of $0.70 US$/C$.
The risk factors and uncertainties that could cause our actual results to differ materially include, but are not limited to: volatility of and other assumptions regarding commodity prices, including the extent to which COVID-19 impacts the global economy and harms commodity prices; the satisfaction of the conditions to closing of the Husky Transaction in a timely manner and complete the arrangement on the expected terms; our ability to successfully integrate the businesses of Cenovus and Husky; access to sufficient capital to pursue any development plans associated with full ownership of Husky; our ability to issue securities after the Husky Transaction closes; the impacts the transaction may have on the current credit ratings of Cenovus and Husky and the credit rating of the company following closing; our ability to achieve our ambition of net zero emissions by 2050; our ability to set new ESG targets for our expanded portfolio; the extent to which COVID-19 and fluctuations in commodity prices associated with COVID-19 impacts our business, results of operations and financial condition, all of which will depend on future developments that are highly uncertain and difficult to predict, including, but not limited to, the duration and spread of the pandemic, its severity, the actions taken to contain COVID-19 or treat its impact and how quickly economic activity normalizes; a resurgence in cases of COVID-19, which has occurred in certain locations and the possibility of which in other locations remains high and
8
creates ongoing uncertainty that could result in restrictions to contain the virus being re-imposed or imposed on a more strict basis, including restrictions on movement and businesses; the success of our COVID-19 protocols and safety measures to protect workers; maintaining sufficient liquidity to sustain operations through a prolonged market downturn; the duration of the market downturn; excessive widening of the WTI-WCS differential; unexpected consequences related to the Government of Alberta’s mandatory production curtailment; the effectiveness of our risk management program; the accuracy of cost estimates regarding commodity prices, currency and interest rates; product supply and demand; accuracy of our share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks, exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; our ability to maintain desirable ratios of net debt to adjusted EBITDA as well as debt to capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; accuracy of our reserves, future production and future net revenue estimates; accuracy of our accounting estimates and judgments; our ability to replace and expand oil and gas reserves; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of our assets or goodwill from time to time; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; our ability to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; unexpected cost increases or potential disruption or unexpected technical difficulties in developing new products and manufacturing processes and in constructing or modifying manufacturing or refining facilities; refining and marketing margins; cost escalations; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation and litigation related thereto; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to our business, including potential cyberattacks; risks associated with climate change and our assumptions relating thereto; our ability to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; possible failure to obtain and retain qualified staff and equipment in a timely and cost efficient manner; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political and economic conditions in the countries in which we operate or which we supply; the occurrence of unexpected events, such as pandemics, fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events, and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against us.
9
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 and the MD&A for the period ended September 30, 2020, and to the risk factors described in other documents Cenovus files from time to time with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Corporation’s website at cenovus.com.
Cenovus Energy Inc.
Cenovus Energy Inc. is a Canadian integrated oil and natural gas company. It is committed to maximizing value by sustainably developing its assets in a safe, innovative and cost-efficient manner, integrating environmental, social and governance considerations into its business plans. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and British Columbia. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE and are listed on the Toronto and New York stock exchanges. For more information, visit cenovus.com.
Find Cenovus on Facebook, Twitter, LinkedIn, YouTube and Instagram.
CENOVUS CONTACTS:
Investor Relations Investor Relations general line 403-766-7711
|
Media Relations Media Relations general line 403-766-7751 |
10
Exhibit 99.2
Management’s Discussion and Analysis
For the PERIOD ended September 30, 2020
|
2 |
|
|
|
|
RESPONDING TO LOW OIL PRICES AND THE NOVEL CORONAVIRUS (“COVID-19”) |
|
2 |
|
|
|
|
3 |
|
|
|
|
|
4 |
|
|
|
|
|
10 |
|
|
|
|
|
12 |
|
|
|
|
|
13 |
|
|
21 |
|
|
24 |
|
|
26 |
|
|
|
|
|
29 |
|
|
|
|
|
32 |
|
|
|
|
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES |
|
34 |
|
|
|
|
35 |
|
|
|
|
|
35 |
|
|
|
|
|
38 |
|
|
|
|
|
41 |
|
|
42 |
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 October 28, 2020, should be read in conjunction with our September 30, 2020 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2019 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2019 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of October 28, 2020, unless otherwise indicated. This MD&A provides an update to our annual MD&A and contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The interim MD&As and the annual MD&A are reviewed by the Audit Committee and recommended for approval by the Cenovus Board of Directors (the “Board”). Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.
Basis of Presentation
This MD&A and the interim Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, (which includes references to “dollar” or “$”), except where another currency has been indicated, and in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board (“IASB”). Production volumes are presented on a before royalties basis.
Non-GAAP Measures and Additional Subtotals
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow, Operating Earnings, Free Funds Flow, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) and therefore are considered non-GAAP measures. In addition, Operating Margin is considered an additional subtotal found in Note 1 of our interim Consolidated Financial Statements. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS.
The definition and reconciliation, if applicable, of each non-GAAP measure or additional subtotal is presented in the Operating and Financial Results, Liquidity and Capital Resources, or Advisory sections of this MD&A.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
1 |
|
|
|
We are a Canadian integrated oil and natural gas company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. Operations include oil sands projects in northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our upstream assets averaged approximately 472,000 BOE per day for the three months ended September 30, 2020. We also conduct marketing activities and have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of 382,000 gross barrels per day of crude oil feedstock into an average of 397,000 gross barrels per day of refined products in the three months ended September 30, 2020.
For a description of our operations, refer to the Reportable Segments section of this MD&A.
On October 25, 2020, Cenovus and Husky Energy Inc. (“Husky”) announced that they have entered into a definitive agreement to combine the two companies in an all-stock transaction to create a new integrated Canadian oil and natural gas company (the “Husky Transaction”). Upon completion of the Husky Transaction, which will require shareholder and regulatory approval, the combined entity will operate as Cenovus and trade under the Cenovus name and remain headquartered in Calgary, Alberta.
Our Strategy
Our overall strategy remains unchanged and continues to be focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We have flexibility in our business plan that allows us to focus on maintaining liquidity and preserving a resilient balance sheet by reducing spending, while maintaining safe and reliable operations. This is particularly important in the current economic environment. Our longer-term plan remains focused on sustainably growing shareholder returns and reducing Net Debt as well as continuing to integrate Environmental, Social and Governance (“ESG”) considerations into our business plan. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility. We aim to evaluate disciplined investment in our portfolio against dividends, share repurchases and achieving and maintaining the optimal debt level while targeting investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage. We plan to achieve our strategy by leveraging our strategic focus areas including our oil sands, conventional oil and natural gas assets, marketing, transportation and refining portfolio, and our people.
RESPONDING TO LOW OIL PRICES AND THE NOVEL CORONAVIRUS (”COVID-19”)
During the first quarter, there was significant crude oil demand reduction as a result of measures taken by governments around the world to contain the COVID-19 pandemic. At the same time, overall global crude oil supply increased as efforts between the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC members, primarily Saudi Arabia and Russia, to manage global crude oil production levels broke down and each party increased their daily crude production. The combination of these events resulted in a collapse of crude oil benchmark prices, dropping to US$10.01 per barrel, excluding a historic one-day low of negative US$37.63 per barrel on April 20, 2020.
In April, the agreement between OPEC and a group of 10 non-OPEC members (collectively, “OPEC+”) to cut crude oil output, and several other countries announcing similar production cuts decreased the global supply of crude oil. At the same time, as governments began to ease off on some of the measures taken to contain the pandemic there was an increase in demand for crude oil which helped increase crude oil prices. During the third quarter, crude oil prices improved from the second quarter, however prices continued to be volatile due to market responses to COVID-19 and OPEC crude oil production output decisions. The duration of the current lower commodity price environment continues to be uncertain, especially with the second wave of COVID-19 infections driving concerns.
We believe our reduced 2020 capital investment plan, operating cost reductions and general and administrative (“G&A”) reductions, announced on April 2, 2020, enhances our financial resilience and financial capability to maintain our base business and to deliver safe and reliable operations. We will continue to challenge our cost structure in the face of these unprecedented conditions.
The Company has available $5.6 billion in committed credit facilities, with $1.1 billion maturing in April 2021, $1.2 billion maturing in late 2022, and $3.3 billion maturing in late 2023. A further $1.6 billion of uncommitted demand lines to issue letters of credit or in some cases draw up to $600 million for general purposes are available, and the Company has no bond maturities until late 2022. We believe that we have ample liquidity and runway to sustain our operations through a prolonged market downturn. Under the terms of Cenovus’s committed credit facilities, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. As at September 30, 2020, the Company was well below this limit.
The Provincial and Federal governments have recognized the serious economic impacts of the spread of COVID‑19 and have taken steps to provide various programs, such as the Canada Emergency Wage Subsidy (“CEWS”)
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
2 |
|
|
|
program. During the third quarter we continued to benefit from the assistance of the CEWS program to help protect jobs during the pandemic.
The Company remains committed to the health and safety of its workforce and the public while providing essential services. Physical distancing measures continue to be taken to maintain the health and safety of our people and to help prevent the spread of COVID-19. We continue to monitor the changing COVID-19 situation. Earlier this month we lifted our mandatory work from home measure to open our modified workspaces in the Calgary offices to staff again, with workplace safety plans and protocols in place. Increases in staff levels at sites and offices has been and will continue to be achieved in accordance with guidance received from the Federal and Provincial governments and public health officials.
Crude oil demand, which continues to be negatively impacted by the effects of COVID-19, showed signs of gradual recovery throughout the summer months with the easing of some of the restrictions imposed by governments to limit the spread of the virus combined with the commitment by OPEC and non-OPEC members to reduce crude oil production levels in response to lower demand and low prices. COVID-19 infection rates, global economic performance and political development will continue to impact the pace of demand recovery.
Brent and WTI crude oil benchmark prices averaged US$43.37 per barrel and US$40.93 per barrel, respectively, for the third quarter. Average crude oil prices have improved significantly from the very low levels in the second quarter (Brent – US$33.27 per barrel; WTI – US$27.85 per barrel), as the market stabilized and the volatility in prices decreased. Even with the improvement, crude oil benchmark prices remain more than 25 percent lower than the third quarter of last year. Western Canadian Select (“WCS”) benchmark prices rose 94 percent from an average low of US$16.38 per barrel in the second quarter to an average of US$31.84 per barrel in the third quarter. However, the average WCS benchmark crude oil prices fell along with the entire crude market, averaging 28 percent lower than US$44.21 per barrel in the same period of 2019. The impact of falling crude prices was partially offset by a narrower differential between WTI and WCS as industry-wide production shut-ins resulted in excess pipeline capacity.
Operationally, our upstream assets performed well. We continued to deliver good health and safety performance in light of the health and wellness challenges presented to staff by the pandemic. In response to increasing crude oil prices we accessed additional production curtailment credits available in the market, which allowed us to produce above our curtailment limit. Our upstream production in the quarter averaged 471,799 BOE per day, five percent higher than the third quarter of 2019, when production was in line with the Government of Alberta’s mandatory production curtailment restrictions. The increase was partially offset by planned turnaround and maintenance activities in the third quarter of 2020. Sales volumes in the quarter were higher than the second quarter as we sold crude oil inventory that had built up from April through June, when the average WTI prices were significantly lower (April – US$16.70 per barrel, May – US$28.53 per barrel and June – US$38.31 per barrel), in July when the average WTI price was US$40.77 per barrel. When the decision was made to store barrels due to those low crude oil prices, we entered into risk management contracts to fix the margin we would receive in the future periods. Although risk management losses were realized, as settlement prices were higher than the contract prices, the corresponding increase in the sales price for the barrels of crude oil offset that and we were able to lock in an improved margin as a result of our decision to store in low pricing months and sell in future periods when prices were higher.
Our Wood River and Borger refineries (the “Refineries”) demonstrated reliable operational performance while continuing to operate below capacity due to economic crude rate reductions in response to lower refined product demand and weak pricing as a result of COVID‑19.
Upstream operating margin of $668 million in the third quarter increased to more than four times that of $157 million in the second quarter due to higher average realized crude oil sales price and higher sales volumes, partially offset by increased transportation and blending costs and higher royalties. Upstream operating margin in the third quarter of 2020 decreased compared with $954 million in 2019, due to a lower average realized crude oil sales price and realized risk management losses compared with gains in 2019, partially offset by higher sales volumes and lower royalties.
Our average realized crude oil sales price of $39.77 per barrel increased significantly compared with $12.83 per barrel in the second quarter due to the improved crude oil prices. However, our average realized crude oil sales price was lower compared with $55.13 per barrel in the third quarter of 2019 reflecting the declining benchmark WTI prices, partially offset by the narrower WTI-WCS differential and lower priced condensate used for blending.
Operating margin for our Refining and Marketing segment was negative $74 million in the third quarter, a decline of $208 million from the second quarter. Refining and Marketing operating margin decreased $200 million compared with the third quarter of 2019 primarily due to decreased market crack spreads, reduced crude oil runs and lower crude advantage, partially offset by lower operating costs.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
3 |
|
|
|
In the third quarter of 2020, we:
• |
Continued our safe and reliable operating performance; |
• |
Demonstrated our ability to use our full suite of assets to maximize prices received for every barrel as we managed to store volumes in a low-price environment and cleared inventory when we could obtain higher prices; |
• |
Increased our Oil Sands production rates to 385,937 barrels per day, responding to the higher crude oil benchmark prices, while managing to reduce the non-fuel per-unit operating costs. Overall, per-unit operating costs increased nine percent to $7.53 per barrel compared with $6.90 per barrel in the third quarter of 2019 due to higher natural gas prices; |
• |
Recognized an impairment charge of $450 million for the Borger cash generating unit (“CGU”), as additional depreciation, depletion and amortization expense; |
• |
Recorded Cash from Operating Activities of $732 million compared with Cash used in Operating Activities of $834 million in the second quarter of 2020 (2019 – Cash from Operating Activities of $834 million); |
• |
Achieved Adjusted Funds Flow of $414 million compared with a deficit of $462 million in the second quarter of 2020 (2019 – Adjusted Funds Flow of $928 million); |
• |
Reduced Net Debt to $7.5 billion and total debt to $7.9 billion from the second quarter of 2020, driven by Free Funds Flow of $266 million; |
• |
Used the proceeds from the issuance of US$1.0 billion in 5.375 percent senior unsecured notes due in 2025 to repay $1.4 billion of borrowings on our committed credit facility; and |
OPERATING AND FINANCIAL RESULTS
Selected Operating Results
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||||||||||
|
2020 |
|
|
Percent Change |
|
|
2019 |
|
|
2020 |
|
|
Percent Change |
|
|
2019 |
|
||||||
Upstream Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands (barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
164,954 |
|
|
|
5 |
|
|
|
156,527 |
|
|
|
164,935 |
|
|
|
4 |
|
|
|
158,888 |
|
Christina Lake |
|
220,983 |
|
|
|
12 |
|
|
|
198,068 |
|
|
|
217,133 |
|
|
|
15 |
|
|
|
188,671 |
|
|
|
385,937 |
|
|
|
9 |
|
|
|
354,595 |
|
|
|
382,068 |
|
|
|
10 |
|
|
|
347,559 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional (1) (BOE per day) |
|
85,862 |
|
|
|
(9 |
) |
|
|
93,901 |
|
|
|
91,196 |
|
|
|
(8 |
) |
|
|
98,807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (BOE per day) |
|
471,799 |
|
|
|
5 |
|
|
|
448,496 |
|
|
|
473,264 |
|
|
|
6 |
|
|
|
446,366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (2) (BOE per day) |
|
428,659 |
|
|
|
8 |
|
|
|
398,304 |
|
|
|
423,677 |
|
|
|
9 |
|
|
|
388,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining and Marketing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Runs (3) (Mbbls/d) |
|
382 |
|
|
|
(18 |
) |
|
|
465 |
|
|
|
383 |
|
|
|
(13 |
) |
|
|
438 |
|
Refined Product (3) (Mbbls/d) |
|
397 |
|
|
|
(18 |
) |
|
|
485 |
|
|
|
396 |
|
|
|
(14 |
) |
|
|
463 |
|
Crude Utilization (3) (percent) |
|
77 |
|
|
|
(19 |
) |
|
|
96 |
|
|
|
77 |
|
|
|
(14 |
) |
|
|
91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude-by-Rail (barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude-by-Rail Loads (4) |
|
- |
|
|
|
(100 |
) |
|
|
68,380 |
|
|
|
33,780 |
|
|
|
(13 |
) |
|
|
38,765 |
|
Crude-by-Rail Sales (5) |
|
- |
|
|
|
(100 |
) |
|
|
62,789 |
|
|
|
40,293 |
|
|
|
11 |
|
|
|
36,212 |
|
(1) |
This segment was previously referred to as the Deep Basin segment. |
(2) |
Less natural gas volumes used for internal consumption by the Oil Sands segment. |
(3) |
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent. |
(4) |
Represents volumes transported outside of Alberta. |
(5) |
Represents volumes sold outside of Alberta. |
Upstream Production Volumes
Oil Sands production for the three and nine months ended September 30, 2020 reflects increased production above our curtailment limit achieved by purchasing additional production curtailment credits compared with 2019, where production was in line with the Government of Alberta’s mandatory production curtailment program. In the third quarter of 2020, production was reduced by 8,528 barrels per day due to a planned turnaround and maintenance at Christina Lake, which began late September and ran until mid-October 2020, and planned maintenance at Foster Creek. In 2019, production was impacted by a planned turnaround at Christina Lake during the second quarter of 2019.
Conventional production in the three months ended September 30, 2020 decreased compared with the third quarter of 2019, due to natural well declines and downtime due to a planned turnaround at a non-operated natural gas plant in the Elmworth-Wapiti area, partially offset by Marten Hills heavy oil production starting in 2020. In the
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
4 |
|
|
|
third quarter of 2019, production was impacted by temporary shut-ins from low natural gas prices. Production in the nine months ended September 30, 2020 decreased due to natural well declines, partially offset by Marten Hills heavy oil production, as well as fewer shut-ins for low commodity pricing.
Refining and Marketing
Crude oil runs and refined product output decreased in the third quarter and on a year-to-date basis compared with the same periods in 2019 as both Refineries implemented crude rate reductions in response to reduced demand and weak pricing for refined products as a result of COVID-19. In 2019, both Refineries were impacted by planned turnarounds and unplanned maintenance. For the three and nine months ended September 30, 2020, the economic crude rate reductions had a greater impact than planned and unplanned maintenance in 2019.
Further information on the changes in our financial and operating results can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements.
Selected Consolidated Financial Results
In 2020, the impact of market factors such as falling crude oil prices, lower refining throughput as a result of low market crack spreads, and volatile blending costs were the primary drivers of our financial results. The following key performance measures are discussed in more detail within this MD&A.
($ millions, except per share |
Nine Months Ended September 30, |
|
2020 |
|
2019 |
|
2018 (1) (2) |
|
|||||||||||||||||||||||||
amounts) |
2020 |
|
2019 |
|
Q3 |
|
Q2 |
|
Q1 |
|
Q4 |
|
Q3 |
|
Q2 |
|
Q1 |
|
Q4 |
|
Q3 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
9,801 |
|
|
15,343 |
|
|
3,659 |
|
|
2,174 |
|
|
3,968 |
|
|
4,838 |
|
|
4,736 |
|
|
5,603 |
|
|
5,004 |
|
|
4,545 |
|
|
5,857 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Margin (3) |
|
296 |
|
|
3,596 |
|
|
594 |
|
|
291 |
|
|
(589 |
) |
|
864 |
|
|
1,080 |
|
|
1,277 |
|
|
1,239 |
|
|
135 |
|
|
1,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
23 |
|
|
2,545 |
|
|
732 |
|
|
(834 |
) |
|
125 |
|
|
740 |
|
|
834 |
|
|
1,275 |
|
|
436 |
|
|
488 |
|
|
1,258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Funds Flow (4) |
|
(194 |
) |
|
3,015 |
|
|
414 |
|
|
(462 |
) |
|
(146 |
) |
|
687 |
|
|
928 |
|
|
1,082 |
|
|
1,005 |
|
|
7 |
|
|
980 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings (Loss) |
|
(2,053 |
) |
|
620 |
|
|
(452 |
) |
|
(414 |
) |
|
(1,187 |
) |
|
(164 |
) |
|
284 |
|
|
267 |
|
|
69 |
|
|
(1,670 |
) |
|
(41 |
) |
Per Share (5) ($) |
|
(1.67 |
) |
|
0.50 |
|
|
(0.37 |
) |
|
(0.34 |
) |
|
(0.97 |
) |
|
(0.13 |
) |
|
0.23 |
|
|
0.22 |
|
|
0.06 |
|
|
(1.36 |
) |
|
(0.03 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
(2,226 |
) |
|
2,081 |
|
|
(194 |
) |
|
(235 |
) |
|
(1,797 |
) |
|
113 |
|
|
187 |
|
|
1,784 |
|
|
110 |
|
|
(1,350 |
) |
|
(242 |
) |
Per Share (5) ($) |
|
(1.81 |
) |
|
1.69 |
|
|
(0.16 |
) |
|
(0.19 |
) |
|
(1.46 |
) |
|
0.09 |
|
|
0.15 |
|
|
1.45 |
|
|
0.09 |
|
|
(1.10 |
) |
|
(0.20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment (6) |
|
599 |
|
|
859 |
|
|
148 |
|
|
147 |
|
|
304 |
|
|
317 |
|
|
294 |
|
|
248 |
|
|
317 |
|
|
276 |
|
|
271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Dividends |
|
77 |
|
|
183 |
|
|
- |
|
|
- |
|
|
77 |
|
|
77 |
|
|
60 |
|
|
62 |
|
|
61 |
|
|
62 |
|
|
61 |
|
Per Share ($) |
|
0.0625 |
|
|
0.1500 |
|
|
- |
|
|
- |
|
|
0.0625 |
|
|
0.0625 |
|
|
0.0500 |
|
|
0.0500 |
|
|
0.0500 |
|
|
0.0500 |
|
|
0.0500 |
|
(1) |
IFRS 16, “Leases” (“IFRS 16”), was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in our 2019 annual MD&A. |
(2) |
Represented on a continuing basis. |
(3) |
Additional subtotal found in Note 1 of the interim Consolidated Financial Statements and defined in this MD&A. |
(4) |
Non-GAAP measure defined in this MD&A. The comparative periods have been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals. |
(5) |
Represented on a basic and diluted per share basis. |
(6) |
Includes expenditures on property, plant and equipment (“PP&E”), Exploration and Evaluation (“E&E”) assets and assets held for sale. |
Operating Margin
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 (1) |
|
|
2020 |
|
|
2019 (1) |
|
||||
Gross Sales |
|
3,920 |
|
|
|
5,273 |
|
|
|
10,444 |
|
|
|
16,638 |
|
Less: Royalties |
|
153 |
|
|
|
332 |
|
|
|
221 |
|
|
|
847 |
|
Revenues |
|
3,767 |
|
|
|
4,941 |
|
|
|
10,223 |
|
|
|
15,791 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
1,444 |
|
|
|
2,026 |
|
|
|
4,170 |
|
|
|
6,622 |
|
Transportation and Blending |
|
1,036 |
|
|
|
1,269 |
|
|
|
3,331 |
|
|
|
3,798 |
|
Operating Expenses |
|
554 |
|
|
|
559 |
|
|
|
1,655 |
|
|
|
1,726 |
|
Production and Mineral Taxes |
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
Inventory Write-Down (Reversal) |
|
- |
|
|
|
16 |
|
|
|
549 |
|
|
|
24 |
|
Realized (Gain) Loss on Risk Management Activities |
|
139 |
|
|
|
(10 |
) |
|
|
222 |
|
|
|
24 |
|
Operating Margin |
|
594 |
|
|
|
1,080 |
|
|
|
296 |
|
|
|
3,596 |
|
(1) |
The comparative period has been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals. |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
5 |
|
|
|
Operating Margin is an additional subtotal found in Note 1 of the interim Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes, inventory write-downs, net of reversals, plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.
Three Months Ended September 30, 2020 Compared With September 30, 2019
Operating Margin Variance
(1) |
Other includes the net effect of the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. |
Operating Margin decreased in the three months ended September 30, 2020 compared with 2019 primarily due to:
• |
A decrease in our average crude oil sales price resulting from lower WTI benchmark pricing; |
• |
Lower Operating Margin from our Refining and Marketing segment due to reduced market crack spreads, reduced crude oil runs and lower crude advantage, partially offset by lower operating costs; and |
• |
Upstream realized risk management losses of $137 million (2019 – gains of $7 million). |
These decreases in Operating Margin were partially offset by:
• |
Higher liquids sales volumes as we sold inventory built up in low pricing months and increased production in response to higher prices; |
• |
Lower royalties due to lower realized prices; and |
• |
A decrease in transportation and blending expenses due to lower condensate price used for blending and lower rail costs, partially offset by higher condensate volumes. |
Nine Months Ended September 30, 2020 Compared With September 30, 2019
Operating Margin Variance
(1) |
Other includes the net effect of the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. |
Operating Margin decreased in 2020 compared with 2019 primarily due to:
• |
A lower average crude oil sales price resulting from lower WTI benchmark pricing and wider WTI-WCS differentials; |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
6 |
|
|
|
decline in Refining and Marketing operating margin was partially offset by higher margins on refined products and lower operating costs; |
• |
Product inventory write-downs, net of reversals, of $316 million related to our upstream assets; and |
• |
Upstream realized risk management losses of $228 million (2019 – losses of $38 million). |
These decreases in Operating Margin were partially offset by:
• |
Higher liquids sales volumes; |
• |
Lower royalties due to lower realized prices; and |
• |
A decrease in transportation and blending expenses due to lower priced condensate used for blending. |
Additional details explaining the changes in Operating Margin can be found in the Reportable Segments section of this MD&A.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as cash from (used in) operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable, inventories (excluding non-cash inventory write-downs and reversals), income tax receivable, accounts payable and income tax payable. Net change in other assets and liabilities is composed of site restoration costs and pension funding.
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Cash From (Used in) Operating Activities |
|
732 |
|
|
|
834 |
|
|
|
23 |
|
|
|
2,545 |
|
(Add) Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Other Assets and Liabilities |
|
(10 |
) |
|
|
(21 |
) |
|
|
(58 |
) |
|
|
(55 |
) |
Net Change in Non-Cash Working Capital (1) |
|
328 |
|
|
|
(73 |
) |
|
|
275 |
|
|
|
(415 |
) |
Adjusted Funds Flow (1) |
|
414 |
|
|
|
928 |
|
|
|
(194 |
) |
|
|
3,015 |
|
(1) |
The comparative period has been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals. |
Cash From Operating Activities and Adjusted Funds Flow decreased for the three months ended September 30, 2020 compared with 2019, primarily due to lower Operating Margin, as discussed above, partially offset by lower current taxes. The change in non-cash working capital as presented in the interim Consolidated Statements of Cash Flows for the third quarter of 2020 was primarily due to a decrease in accounts receivable and an increase in accounts payable, partially offset by an increase in inventory. For the three months ended September 30, 2019, the change in non-cash working capital was due to higher inventories and a decrease in accounts payable, partially offset by a decrease in accounts receivable and income tax receivable.
Cash From Operating Activities and Adjusted Funds Flow decreased for the nine months ended September 30, 2020 compared with 2019, primarily due to lower Operating Margin, as discussed above, partially offset by higher other income due to funding from the CEWS program, and lower current taxes. The change in non-cash working capital for the nine months ended September 30, 2020 was primarily due to a decrease in inventory and accounts receivable, partially offset by a decrease in accounts payable and income taxes payable. In 2019, the change in non-cash working capital was primarily due to an increase in inventory and accounts receivable, partially offset by a decrease in income tax receivable and an increase in accounts payable.
Operating Earnings (Loss)
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before income tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
7 |
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Earnings (Loss), Before Income Tax |
|
(372 |
) |
|
|
239 |
|
|
|
(2,884 |
) |
|
|
1,314 |
|
Add (Deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Risk Management (Gain) Loss (1) |
|
(135 |
) |
|
|
9 |
|
|
|
7 |
|
|
|
157 |
|
Non-Operating Unrealized Foreign Exchange (Gain) Loss (2) |
|
(152 |
) |
|
|
87 |
|
|
|
164 |
|
|
|
(529 |
) |
(Gain) Loss on Divestiture of Assets |
|
(1 |
) |
|
|
3 |
|
|
|
- |
|
|
|
7 |
|
Operating Earnings (Loss), Before Income Tax |
|
(660 |
) |
|
|
338 |
|
|
|
(2,713 |
) |
|
|
949 |
|
Income Tax Expense (Recovery) |
|
(208 |
) |
|
|
54 |
|
|
|
(660 |
) |
|
|
329 |
|
Total Operating Earnings (Loss) |
|
(452 |
) |
|
|
284 |
|
|
|
(2,053 |
) |
|
|
620 |
|
(1) |
Includes the reversal of unrealized (gains) losses recorded in prior periods. |
(2) |
Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange (gains) losses on settlement of intercompany transactions. |
In the third quarter of 2020, we had an Operating Loss compared with Operating Earnings in 2019 primarily due to lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above, and higher depreciation, depletion, and amortization (“DD&A”) that included an impairment charge of $450 million for the Borger CGU, partially offset by non-operating realized foreign exchange gains of $30 million.
We had an Operating Loss for the nine months ended September 30, 2020, relative to Operating Earnings in 2019 primarily due to lower Cash Used in Operating Activities and Adjusted Funds Flow, as discussed above, higher DD&A that included impairment charges of $814 million, and operating unrealized foreign exchange losses of $65 million compared with gains of $18 million in 2019. The increase in our Operating Loss was partially offset by non-operating realized foreign exchange gains of $33 million compared with realized losses of $279 million in 2019 on our unsecured notes, a re‑measurement gain of $97 million on the contingent payment compared with a loss of $137 million in 2019, and lower non-cash employee long-term incentive costs.
Net Earnings (Loss)
($ millions) |
Three Months Ended |
|
|
Nine Months Ended |
|
||
Net Earnings (Loss), for the Periods Ended September 30, 2019 |
|
187 |
|
|
|
2,081 |
|
Increase (Decrease) due to: |
|
|
|
|
|
|
|
Operating Margin |
|
(486 |
) |
|
|
(3,300 |
) |
Corporate and Eliminations: |
|
|
|
|
|
|
|
Unrealized Risk Management Gain (Loss) |
|
144 |
|
|
|
150 |
|
Unrealized Foreign Exchange Gain (Loss) |
|
228 |
|
|
|
(789 |
) |
Re-measurement of Contingent Payment |
|
14 |
|
|
|
234 |
|
Gain (Loss) on Divestiture of Assets |
|
4 |
|
|
|
7 |
|
Expenses (1) |
|
43 |
|
|
|
469 |
|
DD&A |
|
(534 |
) |
|
|
(947 |
) |
Exploration Expense |
|
(24 |
) |
|
|
(22 |
) |
Income Tax Recovery (Expense) |
|
230 |
|
|
|
(109 |
) |
Net Earnings (Loss), for the Periods Ended September 30, 2020 |
|
(194 |
) |
|
|
(2,226 |
) |
(1) |
Includes Corporate and Eliminations realized risk management (gains) losses, general and administrative, onerous contract provisions, finance costs, interest income, realized foreign exchange (gains) losses, research costs, other (income) loss, net, Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses. |
Our Net Loss of $194 million in the third quarter of 2020 was lower than Net Earnings of $187 million in the third quarter of 2019 primarily due to lower Operating Earnings, as discussed above. The decrease to Net Earnings was partially offset by:
• |
Non-operating unrealized foreign exchange gains of $152 million compared with losses of $87 million; |
• |
Unrealized risk management gains of $135 million compared with losses of $9 million; and |
• |
A deferred income tax recovery of $177 million compared with a deferred income tax expense of $46 million. |
On a year-to-date basis, Net Loss of $2,226 million was significantly lower than Net Earnings of $2,081 million in 2019 due to:
• |
Lower Operating Earnings, as discussed above; |
• |
Non-operating unrealized foreign exchange losses of $164 million compared with gains of $529 million in 2019; and |
• |
A deferred income tax recovery of $656 million compared with a recovery of $790 million in 2019. In 2019, we recorded a deferred income tax recovery of $663 million associated with the reduction in the Alberta corporate tax rate and a recovery of $387 million due to a step-up in the tax basis of our refining assets. |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
8 |
|
|
|
The increase in Net Loss was partially offset by lower unrealized risk management losses of $7 million in 2020 compared with $157 million in 2019.
Capital Investment
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 (1) |
|
|
2020 |
|
|
2019 (1) |
|
||||
Oil Sands |
|
65 |
|
|
|
134 |
|
|
|
337 |
|
|
|
477 |
|
Conventional (2) |
|
12 |
|
|
|
32 |
|
|
|
39 |
|
|
|
61 |
|
Refining and Marketing |
|
65 |
|
|
|
87 |
|
|
|
172 |
|
|
|
214 |
|
Corporate and Eliminations |
|
6 |
|
|
|
41 |
|
|
|
51 |
|
|
|
107 |
|
Capital Investment (3) |
|
148 |
|
|
|
294 |
|
|
|
599 |
|
|
|
859 |
|
(1) |
In the first quarter of 2020, our new resource play, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified. |
(2) |
This segment was previously referred to as the Deep Basin segment. |
(3) |
Includes expenditures on PP&E, E&E assets and assets held for sale. |
Capital investment in 2020 decreased compared with 2019, reflecting our reduced capital investment program and revised budget announced in April.
Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
9 |
|
|
|
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, quality and location price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
(US$/bbl, unless otherwise indicated) |
2020 |
|
|
Percent Change |
|
|
2019 |
|
|
Q3 2020 |
|
|
Q2 2020 |
|
|
Q3 2019 |
|
|
||||||
Brent |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
42.53 |
|
|
|
(34 |
) |
|
|
64.74 |
|
|
|
43.37 |
|
|
|
33.27 |
|
|
|
62.00 |
|
|
WTI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
38.32 |
|
|
|
(33 |
) |
|
|
57.06 |
|
|
|
40.93 |
|
|
|
27.85 |
|
|
|
56.45 |
|
|
Average Differential Brent-WTI |
|
4.21 |
|
|
|
(45 |
) |
|
|
7.68 |
|
|
|
2.44 |
|
|
|
5.42 |
|
|
|
5.55 |
|
|
WCS at Hardisty ("WCS") |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
24.63 |
|
|
|
(46 |
) |
|
|
45.32 |
|
|
|
31.84 |
|
|
|
16.38 |
|
|
|
44.21 |
|
|
Average Differential WTI-WCS |
|
13.69 |
|
|
|
17 |
|
|
|
11.74 |
|
|
|
9.09 |
|
|
|
11.47 |
|
|
|
12.24 |
|
|
Average (C$/bbl) |
|
32.98 |
|
|
|
(45 |
) |
|
|
60.26 |
|
|
|
42.41 |
|
|
|
22.42 |
|
|
|
58.38 |
|
|
WCS at Nederland |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
34.36 |
|
|
|
(40 |
) |
|
|
56.93 |
|
|
|
38.73 |
|
|
|
22.55 |
|
|
|
52.76 |
|
|
Average Differential WTI-WCS at Nederland |
|
3.96 |
|
|
|
2,946 |
|
|
|
0.13 |
|
|
|
2.20 |
|
|
|
5.30 |
|
|
|
3.69 |
|
|
West Texas Sour ("WTS") |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
38.15 |
|
|
|
(32 |
) |
|
|
55.93 |
|
|
|
40.96 |
|
|
|
28.03 |
|
|
|
55.88 |
|
|
Average Differential WTI-WTS |
|
0.17 |
|
|
|
(85 |
) |
|
|
1.13 |
|
|
|
(0.03 |
) |
|
|
(0.18 |
) |
|
|
0.57 |
|
|
Condensate (C5 @ Edmonton) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
35.38 |
|
|
|
(33 |
) |
|
|
52.81 |
|
|
|
37.55 |
|
|
|
22.30 |
|
|
|
52.02 |
|
|
Average Differential WTI-Condensate (Premium)/Discount |
|
2.94 |
|
|
|
(31 |
) |
|
|
4.25 |
|
|
|
3.38 |
|
|
|
5.55 |
|
|
|
4.43 |
|
|
Average Differential WCS-Condensate (Premium)/Discount |
|
(10.75 |
) |
|
|
44 |
|
|
|
(7.49 |
) |
|
|
(5.71 |
) |
|
|
(5.92 |
) |
|
|
(7.81 |
) |
|
Average (C$/bbl) |
|
47.47 |
|
|
|
(32 |
) |
|
|
70.21 |
|
|
|
49.99 |
|
|
|
30.70 |
|
|
|
68.69 |
|
|
Average Refined Product Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chicago Regular Unleaded Gasoline ("RUL") |
|
44.55 |
|
|
|
(39 |
) |
|
|
72.45 |
|
|
|
48.75 |
|
|
|
32.91 |
|
|
|
72.07 |
|
|
Chicago Ultra-low Sulphur Diesel ("ULSD") |
|
48.71 |
|
|
|
(37 |
) |
|
|
77.92 |
|
|
|
48.91 |
|
|
|
36.89 |
|
|
|
75.34 |
|
|
Refining Margin: Average 3-2-1 Crack Spreads (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chicago |
|
7.71 |
|
|
|
(55 |
) |
|
|
17.24 |
|
|
|
7.89 |
|
|
|
6.44 |
|
|
|
16.72 |
|
|
Group 3 |
|
9.04 |
|
|
|
(48 |
) |
|
|
17.36 |
|
|
|
8.29 |
|
|
|
7.92 |
|
|
|
17.32 |
|
|
Average Natural Gas Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO (3) (C$/Mcf) |
|
2.07 |
|
|
|
49 |
|
|
|
1.39 |
|
|
|
2.15 |
|
|
|
1.91 |
|
|
|
1.04 |
|
|
NYMEX (US$/Mcf) |
|
1.88 |
|
|
|
(30 |
) |
|
|
2.67 |
|
|
|
1.98 |
|
|
|
1.72 |
|
|
|
2.23 |
|
|
Foreign Exchange Rate (US$ per C$1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
0.739 |
|
|
|
(2 |
) |
|
|
0.752 |
|
|
|
0.751 |
|
|
|
0.722 |
|
|
|
0.757 |
|
|
End of Period |
|
0.750 |
|
|
|
(1 |
) |
|
|
0.755 |
|
|
|
0.750 |
|
|
|
0.734 |
|
|
|
0.755 |
|
|
(1) |
These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management results, refer to the Netback tables in the Reportable Segments section of this MD&A. |
(2) |
The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis. |
(3) |
Alberta Energy Company (“AECO”) natural gas monthly index. |
Crude Oil and Condensate Benchmarks
Through the quarter, crude oil benchmarks improved relative to the second quarter with the average Brent and WTI crude oil benchmark prices rising 30 percent and 47 percent, respectively. While global demand for crude oil in the third quarter improved from the second quarter lows and significant production shut-ins globally helped in stabilizing the market, demand for crude oil was still under pressure due to the resurgence of COVID-19 cases.
Year-over-year, the impacts of the global demand reduction have resulted in the average Brent and WTI crude oil benchmark prices being lower.
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 third quarter of 2020, the Brent-WTI differential narrowed compared with 2019 due to lower exports of crude oil from North America and reduced U.S. crude oil supply.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
10 |
|
|
|
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. In the second quarter of 2020, Alberta production cuts due to demand concerns from COVID-19 resulted in reduced Western Canadian Select Basin (“WCSB”) supply causing heavy oil differentials to significantly narrow. As a result, the WCSB crude supply was able to clear volumes from Alberta by way of pipeline versus more expensive rail. In the third quarter of 2020, the WTI-WCS at Hardisty differential narrowed further from the second quarter as marginal transportation costs remained low and heavy crude benchmarks in the U.S. Gulf Coast (“USGC”) also strengthened relative to WTI due to decreased global supply.
WCS at Nederland is a heavy oil benchmark at the USGC which is representative of pricing for our sales in the USGC. WCS at Nederland crude oil benchmark prices weakened in 2020 compared with 2019, consistent with falling crude oil prices globally as refiners lowered crude runs to adjust to reduced demand for products. In the third quarter of 2020, WCS at Nederland benchmark prices relative to WTI strengthened compared with the second quarter of 2020, benefitting from the lower supply of heavy and medium sour grades from Canadian and OPEC+ producers.
|
|
WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI crude oil, and is a primary component of the input feedstock at the Borger refinery. The average differential between WTI and WTS benchmark prices narrowed in 2020 compared with 2019 as debottlenecking of transportation constraints resulted in WTS trading in a narrow range around parity with WTI pricing since early 2019.
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent volumes as a percentage of total blended volumes, range from approximately 25 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending as well as timing of sales of blended product.
Average condensate benchmark prices were at a narrower discount relative to WTI in Alberta in the third quarter of 2020 compared with 2019. The benefit of weaker diluent demand in 2020 due to shut-in heavy oil production has been offset by lower imported barrels from the U.S. On a year-to-date basis, average condensate differentials to WTI narrowed compared with 2019.
Refining Benchmarks
The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3‑2‑1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI‑based crude oil feedstock prices and valued on a last in, first out accounting basis.
Average Chicago refined product prices decreased in the third quarter and on a year-to-date basis compared with the same periods in 2019, primarily due to lower refined product demand as a result of COVID-19. Weaker refined product demand resulted in higher inventory levels which put pressure on market crack spreads. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by global prices, the weakening of refining market crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and WTI benchmark prices.
Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock, which is valued on a first in, first out (“FIFO”) accounting basis.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
11 |
|
|
|
|
|
Natural Gas Benchmarks
Average AECO prices strengthened during the three and nine months ended September 30, 2020 compared with 2019 as the differential between AECO and NYMEX narrowed significantly due to lower than expected supply, ample access to domestic storage injections and lower pipeline utilization in the WCSB. Average NYMEX prices decreased compared with 2019 due to lower demand and a large decrease in liquid natural gas exports.
Foreign Exchange Benchmark
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian dollar weakens, there is a positive impact on our reported results. In addition to our revenues being denominated in U.S. dollars, our long‑term debt is also U.S. dollar denominated. In periods of a weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars.
The Canadian dollar on average weakened relative to the U.S. dollar in 2020, compared with 2019, resulting in a positive impact of approximately $170 million on our revenues in the nine months ended September 30, 2020. The weakening of the Canadian dollar relative to the U.S. dollar as at September 30, 2020 compared with December 31, 2019, resulted in unrealized foreign exchange losses of $164 million on the translation of our U.S. dollar debt.
Our reportable segments are as follows:
Oil Sands, which includes the development and production of bitumen in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development.
Conventional, which includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, and Clearwater operating areas in Alberta and British Columbia and the exploration for heavy oil in the Marten Hills area. The assets include interests in numerous natural gas processing facilities. We renamed our Deep Basin segment to Conventional in the first quarter of 2020 and our new resource play, Marten Hills, was reclassified from the Oil Sands segment to the Conventional segment. Comparative periods have been reclassified.
Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude‑by‑rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification.
Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
12 |
|
|
|
Revenues by Reportable Segment
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||||||||||
|
September 30, |
|
|
September 30, |
|
||||||||||||||||||
($ millions) |
2020 |
|
|
Percent Change |
|
|
2019 |
|
|
2020 |
|
|
Percent Change |
|
|
2019 |
|
||||||
Oil Sands |
|
2,066 |
|
|
|
(13 |
) |
|
|
2,386 |
|
|
|
5,094 |
|
|
|
(31 |
) |
|
|
7,352 |
|
Conventional (1) |
|
132 |
|
|
|
(2 |
) |
|
|
135 |
|
|
|
423 |
|
|
|
(12 |
) |
|
|
481 |
|
Refining and Marketing |
|
1,569 |
|
|
|
(35 |
) |
|
|
2,420 |
|
|
|
4,706 |
|
|
|
(41 |
) |
|
|
7,958 |
|
Corporate and Eliminations |
|
(108 |
) |
|
|
47 |
|
|
|
(205 |
) |
|
|
(422 |
) |
|
|
6 |
|
|
|
(448 |
) |
|
|
3,659 |
|
|
|
(23 |
) |
|
|
4,736 |
|
|
|
9,801 |
|
|
|
(36 |
) |
|
|
15,343 |
|
(1) |
This segment was previously referred to as the Deep Basin segment. |
Oil Sands revenues decreased in the three and nine months ended September 30, 2020 compared with 2019 due to lower average realized liquids sales price, partially offset by higher sales volumes and lower royalties.
Conventional revenues declined slightly in the three months ended September 30, 2020 compared with the same period of 2019 due to higher royalties, primarily due to a 2019 Gas Cost Allowance (“GCA”) true up, partially offset by a higher average natural gas sales price and production from our Marten Hills asset. On a year-to-date basis, Conventional revenues decreased compared with 2019 due to lower average realized liquids sales prices, lower natural gas sales volumes and higher royalties, partially offset by a higher average natural gas sales price and the commencement of production from our Marten Hills asset.
Refining and Marketing revenues declined 35 percent in the third quarter and 41 percent on a year-to-date basis compared with 2019. Refining revenues decreased due to lower refined product pricing consistent with the decline in average refined product benchmark prices and lower refined product output due to the economic crude rate reductions. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group was relatively flat for the three months ended September 30, 2020 compared with the same period in 2019 due to lower crude oil prices and lower natural gas volumes, offset by higher crude oil volumes and natural gas prices. On a year-to-date basis, marketing revenues decreased compared with 2019 due to lower crude oil prices and lower volumes, partially offset by higher natural gas prices.
Corporate and Eliminations revenues relate to sales of natural gas or crude oil and operating revenues between segments and are recorded at transfer prices based on current market prices.
In the third quarter of 2020, we:
• |
Increased our Oil Sands production rates to 385,937 barrels per day to produce above our curtailment limit by purchasing production curtailment credits to respond to higher crude oil benchmark prices, while managing to reduce the non-fuel per-unit operating costs. Overall, per-unit operating costs increased nine percent to $7.53 per barrel compared with $6.90 per barrel in the third quarter of 2019 due to higher natural gas prices; |
• |
Demonstrated our ability to use our full suite of assets to maximize prices received for every barrel as we managed to store volumes in a low-price environment and cleared inventory when we could obtain higher prices; and |
• |
Generated Operating Margin of $638 million, a decrease of $279 million compared with the third quarter of 2019 due to lower average realized sales prices, realized risk management losses compared with gains in 2019, partially offset by lower transportation and blending costs, higher volumes and lower royalties. |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
13 |
|
|
|
Three Months Ended September 30, 2020 Compared With September 30, 2019
Financial Results
|
Three Months Ended September 30, |
|
|
|||||
($ millions) |
2020 |
|
|
2019 |
|
|
||
Gross Sales |
|
2,195 |
|
|
|
2,722 |
|
|
Less: Royalties |
|
129 |
|
|
|
336 |
|
|
Revenues |
|
2,066 |
|
|
|
2,386 |
|
|
Expenses |
|
|
|
|
|
|
|
|
Transportation and Blending |
|
1,015 |
|
|
|
1,249 |
|
|
Operating |
|
276 |
|
|
|
227 |
|
|
(Gain) Loss on Risk Management |
|
137 |
|
|
|
(7 |
) |
|
Operating Margin |
|
638 |
|
|
|
917 |
|
|
Depreciation, Depletion and Amortization |
|
469 |
|
|
|
391 |
|
|
Exploration Expense |
|
- |
|
|
|
1 |
|
|
Segment Income (Loss) |
|
169 |
|
|
|
525 |
|
|
Operating Margin Variance
(1) |
Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. |
Revenues
Our realized crude oil sales price was $39.67 per barrel in the third quarter (2019 – $54.94 per barrel), consistent with the overall decline in crude oil benchmark pricing led by a 28 percent decline in WTI average benchmark price, partially offset by the narrowing of the WTI-WCS differential to an average discount of US$9.09 per barrel (2019 – discount of US$12.24 per barrel), narrower WCS-Christina Dilbit Blend (“CDB”) differential and lower priced condensate used for blending. The WCS-CDB differential narrowed to a historically low discount of US$1.07 per barrel (2019 – discount of US$2.00 per barrel) mainly due to increased demand for the CDB crude type. In the three months ended September 30, 2020, we sold approximately 20 percent (2019 – approximately one third) of our production at sales locations outside of Alberta, to improve our realized sales price.
The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Our realized crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios range between 25 percent and 33 percent. As the cost of condensate decreases relative to the price of blended crude oil, our realized bitumen sales price increases. Due to high demand for condensate at Edmonton, we also purchase condensate from U.S. markets and deliver it to the Edmonton hub. As such, our average cost of condensate is generally higher than the Edmonton benchmark price due to transportation between market hubs and transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to when we sell our blended production. In a declining crude oil price environment, we expect to see a negative impact on our realized bitumen sales price as we are using condensate purchased at a higher price earlier in the year. During the quarter we reduced condensate volumes transported from the USGC, shipping when the price differential between market hubs is significant enough to cover variable transportation costs.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
14 |
|
|
|
|
Three Months Ended September 30, |
|
|||||||||
(barrels per day) |
2020 |
|
|
Percent Change |
|
|
2019 |
|
|||
Foster Creek |
|
164,954 |
|
|
|
5 |
|
|
|
156,527 |
|
Christina Lake |
|
220,983 |
|
|
|
12 |
|
|
|
198,068 |
|
|
|
385,937 |
|
|
|
9 |
|
|
|
354,595 |
|
Production at Foster Creek increased year-over-year with the facility targeting maximum production rates, other than during planned maintenance. During the quarter, we were able to purchase additional production curtailment credits allowing us to operate Christina Lake at increased production levels as commodity prices improved. Planned turnaround and maintenance commenced at Christina Lake in late September reducing production. In the three months ended September 30, 2019, production volumes were reduced due to the government curtailment program restrictions.
Royalties
Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.
Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.
Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). For royalty purposes, gross revenues are a function of sales revenues less diluent costs and transportation costs and net profits are a function of sales revenues less diluent costs, transportation costs, and allowed operating and capital costs.
Foster Creek and Christina Lake are post-payout projects for determining royalties.
Effective Royalty Rates
|
Three Months Ended September 30, |
|
|
|||||
(percent) |
2020 |
|
|
2019 |
|
|
||
Foster Creek |
|
7.4 |
|
|
|
21.8 |
|
|
Christina Lake |
|
13.4 |
|
|
|
24.2 |
|
|
In the third quarter of 2020, royalties decreased $207 million compared with 2019, as a result of lower net profits due to lower commodity pricing, combined with lower Alberta Department of Energy posted royalty rates resulting from decreased annual average WTI benchmark pricing.
Expenses
Transportation and blending costs decreased $234 million compared with the third quarter of 2019. Blending costs decreased due to lower priced condensate, partially offset by higher condensate volumes as a result of increased sales volumes. 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 were lower due to the temporary suspension of our crude-by-rail program as we now only incur fixed costs associated with the program. The lower transportation costs were partially offset by higher fixed costs as our freight and offloading commitments escalated after the third quarter of 2019. In addition, we entered into a new tankage and offloading commitment at the end of September 2019. In the third quarter of 2020, we transported approximately 20 percent of our volumes to U.S. destinations by pipeline, compared with approximately one third in 2019, by pipeline and rail. Our crude-by-rail program continues to be temporarily suspended and we anticipate transportation costs will continue to be lower while the temporary suspension is in place.
Per-unit Transportation Expenses
Foster Creek per-unit transportation costs decreased $4.59 per barrel to $8.59 per barrel due to lower rail sales, partially offset by higher fixed rail transportation costs, as discussed above. Christina Lake per-unit transportation costs decreased $0.42 per barrel to $6.78 per barrel as a result of increased total sales volumes and lower rail sales, partially offset by higher pipeline tariff rates and higher fixed rail transportation costs, as discussed above.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
15 |
|
|
|
Operating expenses in the third quarter focused on maintaining safe and reliable operations. Total and per-unit operating costs increased year over year primarily due to higher fuel costs from increased natural gas prices. Non-fuel costs increased mainly due to increased electricity prices and workover costs due to increased production. Non-fuel per-unit operating costs at Foster Creek were relatively flat, while at Christina Lake higher sales volumes reduced non-fuel per-unit operating costs.
Per-unit Operating Expenses
|
Three Months Ended September 30, |
|
|||||||||
($/bbl) |
2020 |
|
|
Percent Change |
|
|
2019 |
|
|||
Foster Creek |
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
2.60 |
|
|
|
59 |
|
|
|
1.64 |
|
Non-fuel |
|
6.44 |
|
|
|
1 |
|
|
|
6.36 |
|
Total |
|
9.04 |
|
|
|
13 |
|
|
|
8.00 |
|
Christina Lake |
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
2.03 |
|
|
|
68 |
|
|
|
1.21 |
|
Non-fuel |
|
4.50 |
|
|
|
(5 |
) |
|
|
4.75 |
|
Total |
|
6.53 |
|
|
|
10 |
|
|
|
5.96 |
|
Total |
|
7.53 |
|
|
|
9 |
|
|
|
6.90 |
|
Netbacks (1)
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to transport it to market. For a reconciliation of our Netbacks see the Advisory section of this MD&A.
|
Foster Creek |
Christina Lake |
|
||||||||||||
|
Three Months Ended September 30, |
|
|||||||||||||
($/bbl) |
2020 (2) |
|
|
2019 |
|
|
2020 (2) |
|
|
2019 |
|
||||
Sales Price |
|
41.51 |
|
|
|
58.89 |
|
|
|
38.44 |
|
|
|
51.62 |
|
Royalties |
|
2.44 |
|
|
|
9.90 |
|
|
|
4.27 |
|
|
|
10.62 |
|
Transportation and Blending |
|
8.59 |
|
|
|
13.18 |
|
|
|
6.78 |
|
|
|
7.20 |
|
Operating Expenses |
|
9.04 |
|
|
|
8.00 |
|
|
|
6.53 |
|
|
|
5.96 |
|
Netback Excluding Realized Risk Management |
|
21.44 |
|
|
|
27.81 |
|
|
|
20.86 |
|
|
|
27.84 |
|
Realized Risk Management Gain (Loss) |
|
(3.67 |
) |
|
|
0.13 |
|
|
|
(3.77 |
) |
|
|
0.27 |
|
Netback Including Realized Risk Management |
|
17.77 |
|
|
|
27.94 |
|
|
|
17.09 |
|
|
|
28.11 |
|
(1) |
Netbacks reflect our margin on a per-barrel basis of unblended crude oil. |
(2) |
The netbacks do not reflect non-cash write-downs or reversals of product inventory. |
Our average Netback, excluding realized risk management gains and losses, decreased in the third quarter compared with 2019, primarily due to lower realized sales prices, higher per-unit operating costs, partially offset by lower per-unit royalties and transportation and blending costs, and higher sales volumes at Christina Lake. For the three months ended September 30, 2020, the weakening of the Canadian dollar relative to the U.S. dollar compared with the same period of 2019 had a positive impact on our reported sales price of approximately $0.33 per barrel.
Risk Management – Cash Flow
Risk management positions in the third quarter of 2020 resulted in realized losses of $11 million (2019 – realized losses of $nil) due to settled commodity prices compared with our contract prices on risk management contracts. These risk management positions are placed to protect both near-term and future cash flows.
Risk Management – Optimization
Risk management positions in the third quarter of 2020 resulted in realized losses of $126 million (2019 – realized gains of $7 million) due to our decisions to store rather than sell our physical crude oil and condensate volumes, as discussed below. Cenovus uses its marketing and transportation initiatives, including storage and pipeline assets to optimize product mix, delivery points, transportation commitments and customer diversification, to inventory physical positions. At the time we make decisions to store crude oil and condensate volumes, the prices available for the future periods we plan to sell in can be locked in and the improved margin realized in the future periods,
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
16 |
|
|
|
which are superior to short-term prices. The fluctuations in revenues generated from the underlying physical sales will be mitigated by the related risk management gains and losses.
Transactions typically span across periods in order to execute the optimization strategy and these transactions reside across both realized and unrealized risk management. As the financial contracts settle, they will flow from unrealized to realized risk management gains and losses and final settlement will match when the physical product is sold.
Nine Months Ended September 30, 2020 Compared With September 30, 2019
Financial Results
|
Nine Months Ended September 30, |
|
|||||
($ millions) |
2020 |
|
|
2019 |
|
||
Gross Sales |
|
5,287 |
|
|
|
8,179 |
|
Less: Royalties |
|
193 |
|
|
|
827 |
|
Revenues |
|
5,094 |
|
|
|
7,352 |
|
Expenses |
|
|
|
|
|
|
|
Transportation and Blending |
|
3,268 |
|
|
|
3,736 |
|
Operating |
|
785 |
|
|
|
771 |
|
Inventory Write-Down (Reversal) |
|
316 |
|
|
|
- |
|
(Gain) Loss on Risk Management |
|
228 |
|
|
|
38 |
|
Operating Margin |
|
497 |
|
|
|
2,807 |
|
Depreciation, Depletion and Amortization |
|
1,275 |
|
|
|
1,127 |
|
Exploration Expense |
|
7 |
|
|
|
10 |
|
Segment Income (Loss) |
|
(785 |
) |
|
|
1,670 |
|
Operating Margin Variance
(1) |
Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. |
Revenues
In the nine months ended September 30, 2020, our realized crude oil sales price was $25.21 per barrel compared with $55.82 per barrel in 2019, consistent with the overall declines in crude oil benchmark pricing led by a decrease in WTI average benchmark price, the widening of the WTI-WCS differential to an average of US$13.69 per barrel (2019 – US$11.74 per barrel), partially offset by the lower average price of condensate of US$35.38 per barrel (2019 – US$52.81 per barrel). The decrease in our crude oil price also reflects the wider WCS-Condensate premium of US$10.75 per barrel (2019 – premium of US$7.49 per barrel). In the nine months ended September 30, 2020, we sold approximately one quarter of our production volumes at sales locations outside of Alberta as our storage capabilities outside of Alberta increased allowing us to respond to price signals. In 2019, we sold approximately one quarter of our production at sales locations outside of Alberta due to volumes shipped by rail.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
17 |
|
|
|
|
Nine Months Ended September 30, |
|
|||||||||
(barrels per day) |
2020 |
|
|
Percent Change |
|
|
2019 |
|
|||
Foster Creek |
|
164,935 |
|
|
|
4 |
|
|
|
158,888 |
|
Christina Lake |
|
217,133 |
|
|
|
15 |
|
|
|
188,671 |
|
|
|
382,068 |
|
|
|
10 |
|
|
|
347,559 |
|
Overall, production levels in the nine months ended September 30, 2020 were higher than 2019, when our production was in line with the Government of Alberta’s mandatory production curtailment program. In 2020, we actively managed production levels to respond to price signals and the availability of production curtailment credits, both our own and those available in the market. In addition, the production increases were partially offset by our planned turnaround and maintenance at Christina Lake in the third quarter which had less of an impact than the Christina Lake planned turnaround in the second quarter of 2019.
Royalties
Effective Royalty Rates
|
Nine Months Ended September 30, |
|
|||||
(percent) |
2020 |
|
|
2019 |
|
||
Foster Creek |
|
9.2 |
|
|
|
17.4 |
|
Christina Lake |
|
13.0 |
|
|
|
20.6 |
|
On a year-to-date basis, royalties decreased $634 million compared with 2019 as a result of lower net profits due to lower commodity pricing, combined with lower Alberta Department of Energy posted royalty rates from decreased annual average WTI benchmark pricing.
Expenses
Year over year, transportation and blending costs have decreased $468 million. Blending costs decreased due to a decline in condensate price, partially offset by increased condensate volumes required to move increased bitumen volumes. 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 and timing of when condensate was purchased.
Transportation costs increased primarily due to higher fixed costs in 2020, as our rail freight and offloading commitments escalated after the third quarter of 2019. In addition, we entered into a new tankage and offloading commitment at the end of September 2019. On a year-to-date basis, before the suspension of our rail program, we shipped by rail 33,780 barrels per day to locations outside of Alberta (2019 – 38,765 barrels per day). Transporting our volumes to U.S. destinations, either by pipeline or rail, allows us to achieve better market prices.
Per-unit Transportation Expenses
Foster Creek per-barrel transportation costs increased $0.72 per barrel due to increased rail transportation costs from higher fixed costs in 2020, as discussed above, partially offset by lower pipeline tariffs as a result of lower sales to U.S. destinations and increased sales volumes. Christina Lake transportation costs increased $0.93 per barrel as a result of higher fixed costs, as discussed above, increased pipeline tariff rates, and higher storage costs, partially offset by increased sales volumes relative to 2019.
Primary drivers of our operating expenses in 2020 were fuel, workforce, chemical costs, and repairs and maintenance. Total operating costs increased $14 million due to higher fuel, workforce, and chemical costs due to increased production, partially offset by lower repairs and maintenance costs and fluid, waste handling and trucking costs due to the planned turnaround at Christina Lake in the second quarter of 2019.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
18 |
|
|
|
At both Foster Creek and Christina Lake, per-barrel fuel costs increased due to higher natural gas prices, partially offset by higher sales volumes.
Per-barrel non-fuel operating expenses at Foster Creek decreased in 2020 primarily due to higher sales volumes and COVID-19 safety measures implemented in the second quarter resulting in less repairs and maintenance activity, partially offset by higher workforce costs.
Per-barrel non-fuel operating expenses at Christina Lake decreased in 2020 primarily due to higher sales volumes, and lower costs due to the planned turnaround in 2019, partially offset by higher workforce and chemical costs.
Inventory Write-Down (Reversal)
In the first quarter of 2020, we recorded $335 million in inventory write-downs of our crude oil blend and condensate, and subsequently reversed $19 million due to improved crude oil prices.
Netbacks (1)
|
Foster Creek |
|
|
Christina Lake |
|
||||||||||
|
Nine Months Ended September 30, |
|
|||||||||||||
($/bbl) |
2020 (2) |
|
|
2019 |
|
|
2020 (2) |
|
|
2019 |
|
||||
Sales Price |
|
27.31 |
|
|
|
59.04 |
|
|
|
23.64 |
|
|
|
53.02 |
|
Royalties |
|
1.47 |
|
|
|
8.19 |
|
|
|
2.18 |
|
|
|
9.44 |
|
Transportation and Blending |
|
11.48 |
|
|
|
10.76 |
|
|
|
7.09 |
|
|
|
6.16 |
|
Operating Expenses |
|
8.88 |
|
|
|
9.08 |
|
|
|
6.56 |
|
|
|
7.40 |
|
Netback Excluding Realized Risk Management |
|
5.48 |
|
|
|
31.01 |
|
|
|
7.81 |
|
|
|
30.02 |
|
Realized Risk Management Gain (Loss) |
|
(2.10 |
) |
|
|
(0.35 |
) |
|
|
(2.17 |
) |
|
|
(0.45 |
) |
Netback Including Realized Risk Management |
|
3.38 |
|
|
|
30.66 |
|
|
|
5.64 |
|
|
|
29.57 |
|
(1) |
Netbacks reflect our margin on a per-barrel basis of unblended crude oil. |
(2) |
The netbacks do not reflect non-cash write-downs or reversals of product inventory. |
Our average Netback, excluding realized risk management gains and losses, decreased in 2020 compared with 2019, primarily due to lower realized sales prices, higher per-unit transportation and blending costs, partially offset by lower per-unit royalties and operating costs, and higher sales volumes. The weakening of the Canadian dollar relative to the U.S. dollar compared with 2019 had a positive impact on our overall reported sales price of approximately $0.43 per barrel.
Risk Management
Risk Management – Cash Flow
Risk management positions in 2020 resulted in realized losses of $15 million (2019 – realized losses of $16 million), due to settled commodity prices compared with our contract prices on risk management contracts. These risk management positions are placed to protect both near-term and future cash flows.
Risk Management – Optimization
Risk management positions in 2020 resulted in realized losses of $213 million (2019 – realized losses of $22 million) due to our decisions to store rather than sell our physical crude oil and condensate volumes. Cenovus uses its marketing and transportation initiatives, including storage and pipeline assets to optimize product mix, delivery points, transportation commitments and customer diversification, to inventory physical positions. At the time we make the decision to store crude oil and condensate volumes, the prices available for future periods we plan to sell in can be locked in and the improved margin realized in the future periods, which are superior to short-term prices. The fluctuations in revenues generated from the underlying physical sales will be mitigated by the related risk management gains and losses.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
19 |
|
|
|
Transactions typically span across periods in order to execute the optimization strategy and these transactions reside across both realized and unrealized risk management. As the financial contracts settle, they will flow from unrealized to realized risk management gains and losses and final settlement will match when the physical product is sold.
DD&A
We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The unit‑of‑production rate accounts for expenditures incurred to date, together with estimated future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A each period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves.
In the three months ended September 30, 2020, Oil Sands DD&A increased $78 million compared with 2019 due to $46 million of previously capitalized PP&E costs written off as additional DD&A and higher sales volumes, partially offset by a decrease in our average depletion rates. On a year-to-date basis, DD&A increased $148 million compared with the same period of 2020, due to higher sales volumes, partially offset by a decrease in our average depletion rates. Our depletion rate decreased due to lower future development costs and a decrease in maintenance capital. The average depletion rate for the nine months ended September 30, 2020 was approximately $10.40 per barrel (2019 – $11.15 per barrel).
We depreciate our ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease term.
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Foster Creek |
|
32 |
|
|
|
46 |
|
|
|
157 |
|
|
|
169 |
|
Christina Lake |
|
27 |
|
|
|
84 |
|
|
|
117 |
|
|
|
279 |
|
|
|
59 |
|
|
|
130 |
|
|
|
274 |
|
|
|
448 |
|
Other (1) |
|
6 |
|
|
|
4 |
|
|
|
63 |
|
|
|
29 |
|
Capital Investment (2) |
|
65 |
|
|
|
134 |
|
|
|
337 |
|
|
|
477 |
|
(1) |
Includes Narrows Lake, Telephone Lake and new resource plays. In Q1 2020, our new resource play, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified. |
(2) |
Includes expenditures on PP&E and E&E assets. |
In 2020, Oil Sands capital investment focused on sustaining programs related to existing production at Foster Creek and Christina Lake as well as the stratigraphic test well program. Other capital investment related to advancing key initiatives and technology development costs. In 2019, capital investment primarily related to sustaining and stratigraphic test well programs and the completion of Christina Lake phase G construction.
Drilling Activity
|
Gross Stratigraphic Test Wells |
|
|
Gross Production Wells (1) (2) |
|
||||||||||
Nine Months Ended September 30, |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Foster Creek |
|
38 |
|
|
|
14 |
|
|
|
- |
|
|
|
- |
|
Christina Lake |
|
42 |
|
|
|
18 |
|
|
|
- |
|
|
|
11 |
|
|
|
80 |
|
|
|
32 |
|
|
|
- |
|
|
|
11 |
|
Other |
|
75 |
|
|
|
14 |
|
|
|
- |
|
|
|
- |
|
|
|
155 |
|
|
|
46 |
|
|
|
- |
|
|
|
11 |
|
(1) |
Steam-assisted gravity drainage well pairs are counted as a single producing well. |
(2) |
In Q1 2020, our new resource play, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified. |
Stratigraphic test wells were drilled in the first quarter to help identify well pad locations for sustaining wells and future expansion phases, and to further progress the evaluation of emerging assets.
Future Capital Investment
Oil Sands capital investment for 2020 is forecast to be between $370 million and $420 million, focused on sustaining capital. At current commodity prices we do not expect to sanction any new projects including phase H expansions at both Christina Lake and Foster Creek.
In 2020, we plan to spend a minimal amount of capital as a result of the challenging commodity price environment.
In 2020, our Technology and other capital investment, forecast to be between $35 million and $40 million, relates to advancing only select strategic initiatives such as solvents, partial upgrading and plant redesign that are
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
20 |
|
|
|
expected to provide both cost and environmental benefits. Guidance dated April 1, 2020 is available on our website at cenovus.com.
In the third quarter of 2020, we:
• |
Demonstrated good health and safety performance in light of the challenges presented by COVID-19; |
• |
Produced a total of 85,862 BOE per day, a decrease compared with 2019 due to natural well declines and increased downtime due to a planned turnaround at a non-operated gas plant in the Elmworth-Wapiti area, partially offset by added production from the Marten Hills area. In the third quarter of 2019, production was impacted by temporary shut-ins from low natural gas prices; |
• |
Generated Operating Margin of $30 million, a decrease from the same period of 2019 due to higher royalties from the 2019 annual true up of GCA, lower sales volumes and higher operating costs, partially offset by a higher realized natural gas sales price; and |
• |
Earned a Netback of $3.16 per BOE, excluding realized risk management activities. |
Financial Results
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Gross Sales |
|
156 |
|
|
|
131 |
|
|
|
451 |
|
|
|
501 |
|
Less: Royalties |
|
24 |
|
|
|
(4 |
) |
|
|
28 |
|
|
|
20 |
|
Revenues |
|
132 |
|
|
|
135 |
|
|
|
423 |
|
|
|
481 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
21 |
|
|
|
20 |
|
|
|
63 |
|
|
|
62 |
|
Operating |
|
81 |
|
|
|
77 |
|
|
|
246 |
|
|
|
257 |
|
Production and Mineral Taxes |
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
Operating Margin |
|
30 |
|
|
|
37 |
|
|
|
114 |
|
|
|
161 |
|
Depreciation, Depletion and Amortization |
|
75 |
|
|
|
78 |
|
|
|
563 |
|
|
|
247 |
|
Exploration Expense |
|
25 |
|
|
|
- |
|
|
|
25 |
|
|
|
- |
|
Segment Income (Loss) |
|
(70 |
) |
|
|
(41 |
) |
|
|
(474 |
) |
|
|
(86 |
) |
Operating Margin Variance
Three Months Ended September 30, 2020 Compared With September 30, 2019
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
21 |
|
|
|
Nine Months Ended September 30, 2020 Compared With September 30, 2019
Revenues
Price
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Heavy Oil ($/bbl) |
|
39.54 |
|
|
|
- |
|
|
|
29.80 |
|
|
|
- |
|
Light and Medium Oil ($/bbl) |
|
49.19 |
|
|
|
68.53 |
|
|
|
42.15 |
|
|
|
66.08 |
|
NGLs ($/bbl) |
|
21.38 |
|
|
|
22.16 |
|
|
|
20.26 |
|
|
|
26.08 |
|
Natural Gas ($/mcf) |
|
2.34 |
|
|
|
1.21 |
|
|
|
2.18 |
|
|
|
1.82 |
|
Total Oil Equivalent ($/BOE) |
|
18.28 |
|
|
|
13.84 |
|
|
|
16.64 |
|
|
|
17.03 |
|
Revenues declined slightly for the three months ended September 30, 2020 compared with 2019 as the higher natural gas prices were more than offset by higher royalties. For the nine months ended September 30, 2020, revenues declined compared with 2019 due to decreased average realized liquids sales prices and lower natural gas sales volumes, partially offset by higher liquids sales volumes. In 2020, we had heavy oil production from Marten Hills of approximately 3,000 barrels per day. For the three and nine months ended September 30, 2020, revenues included $11 million and $35 million, respectively, of processing fee revenue related to our interests in natural gas processing facilities (2019 – $12 million and $42 million, respectively). We do not include processing fee revenue in our per-unit pricing metrics or our Netbacks.
Production Volumes
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|||||
Liquids |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (barrels per day) |
|
7,554 |
|
|
|
4,929 |
|
|
|
7,585 |
|
|
|
4,885 |
|
NGLs (barrels per day) |
|
18,297 |
|
|
|
21,175 |
|
|
|
19,901 |
|
|
|
21,950 |
|
|
|
25,851 |
|
|
|
26,104 |
|
|
|
27,486 |
|
|
|
26,835 |
|
Natural Gas (MMcf per day) |
|
360 |
|
|
|
407 |
|
|
|
382 |
|
|
|
432 |
|
Total Production (BOE/d) |
|
85,862 |
|
|
|
93,901 |
|
|
|
91,196 |
|
|
|
98,807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Production (percentage of total) |
|
70 |
|
|
|
72 |
|
|
|
70 |
|
|
|
73 |
|
Liquids Production (percentage of total) |
|
30 |
|
|
|
28 |
|
|
|
30 |
|
|
|
27 |
|
Production for the three months ended September 30, 2020 declined nine percent, compared with 2019 due to natural declines from lower sustaining capital investment and increased downtime due to a planned turnaround at a non-operated gas plant in the Elmworth-Wapiti area, partially offset by Marten Hills heavy oil production starting in 2020. In the third quarter of 2019, production was impacted by temporary shut-ins from low natural gas prices. Production for the nine months ended September 30, 2020 decreased eight percent compared with 2019 due to natural well declines, partially offset by Marten Hills heavy oil production and fewer shut-ins for low commodity pricing.
The Conventional assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties benefit from a number of different programs that reduce the royalty rate on crude oil and natural gas production. Natural gas wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital and operating costs incurred to process and transport the Crown’s share of raw gas at producer-owned gas plants as well as transport the Crown’s share of residue gas, NGLs or oil through producer-owned plants.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
22 |
|
|
|
For the three and nine months ended September 30, 2020, our effective royalty rate was 18.5 percent and 7.7 percent, respectively (2019 – negative 3.4 percent and 5.1 percent, respectively). The higher royalty rates are due to a 2019 GCA royalty true up of $8 million booked in 2020, as a result of a reduction in capital and operating expenses in 2019.
Expenses
Transportation
Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. The majority of our Conventional production is sold into the Alberta market. For the three months ended September 30, 2020 and on a year-to-date basis, per-unit transportation costs averaged $2.62 per BOE (2019 – $2.28 per BOE) and averaged $2.51 per BOE (2019 – $2.29 per BOE), respectively, due to lower sales volumes and increased pipeline costs.
Total operating costs in the three months ended September 30, 2020 increased to $81 million (2019 – $77 million) due to planned turnaround costs, higher third-party processing fees, and operating costs related to Marten Hills production. For the nine months ended September 30, 2020 total operating costs decreased to $246 million (2019 – $257 million) as a result of optimizing operations, focusing on critical repair and maintenance activities and leveraging our infrastructure to lower the cost structure.
Per-unit operating costs increased to average $9.55 per BOE (2019 – $8.21 per BOE) in the three months ended September 30, 2020 as a result of lower sales volumes and higher repairs and maintenance activity primarily due to planned turnaround costs and higher third-party processing fees. On a year-to-date basis, per-unit operating costs increased to an average of $9.19 per BOE (2019 – $8.83 per BOE) primarily due to lower sales volumes and higher third-party processing fees.
These increases were partially offset by:
• |
decreased property tax and lease costs primarily for lower lease rentals and from regulatory cost relief; |
• |
lower workforce costs; and |
• |
lower repairs and maintenance as a result of lower activity and deferrals. |
Netbacks
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($/BOE) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Sales Price |
|
18.28 |
|
|
|
13.84 |
|
|
|
16.64 |
|
|
|
17.03 |
|
Royalties |
|
2.93 |
|
|
|
(0.41 |
) |
|
|
1.09 |
|
|
|
0.76 |
|
Transportation and Blending |
|
2.62 |
|
|
|
2.28 |
|
|
|
2.51 |
|
|
|
2.29 |
|
Operating Expenses |
|
9.55 |
|
|
|
8.21 |
|
|
|
9.19 |
|
|
|
8.83 |
|
Production and Mineral Taxes |
|
0.02 |
|
|
|
0.03 |
|
|
|
- |
|
|
|
0.03 |
|
Netback Excluding Realized Risk Management |
|
3.16 |
|
|
|
3.73 |
|
|
|
3.85 |
|
|
|
5.12 |
|
Realized Risk Management Gain (Loss) |
|
(0.03 |
) |
|
|
- |
|
|
|
(0.01 |
) |
|
|
(0.01 |
) |
Netback Including Realized Risk Management |
|
3.13 |
|
|
|
3.73 |
|
|
|
3.84 |
|
|
|
5.11 |
|
DD&A and Exploration Expense
We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit‑of‑production rate accounts for expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves. The average depletion rate was approximately $9.60 per BOE and $10.00 per BOE for the three and nine months ended September 30, 2020, respectively (2019 – $8.90 per BOE and $9.10 per BOE, respectively).
For the three and nine months ended September 30, 2020, total Conventional DD&A was $75 million and $563 million, respectively (2019 – $78 million and $247 million, respectively). The DD&A was slightly lower compared with the third quarter of 2019 due to lower sales volumes offset by higher DD&A rates. On a year-to-date basis the increase was due to an impairment write-down of $315 million as a result of the decline in forward crude oil and natural gas prices and higher DD&A rates.
Exploration expense of $25 million was recorded in the three and nine months ended September 30, 2020 (2019 – $nil) related to previously capitalized E&E costs written off as we have relinquished the legal right to explore on certain leased acreage.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
23 |
|
|
|
In the three and nine months ended September 30, 2020, we invested $12 million and $39 million, respectively, compared with $32 million and $61 million for the same periods of 2019. Capital investment to date focused on the disciplined development of our Conventional assets, which encompassed maintaining safe and reliable operations, acquiring seismic data, start-up of a recompletion program to optimize existing production and commencement of activities to support drilling and infrastructure.
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 (1) |
|
|
2020 |
|
|
2019 (1) |
|
||||
Seismic |
|
- |
|
|
|
- |
|
|
|
5 |
|
|
|
- |
|
Drilling and Completions |
|
1 |
|
|
|
11 |
|
|
|
2 |
|
|
|
13 |
|
Facilities |
|
5 |
|
|
|
12 |
|
|
|
15 |
|
|
|
21 |
|
Other |
|
6 |
|
|
|
9 |
|
|
|
17 |
|
|
|
27 |
|
Capital Investment (2) |
|
12 |
|
|
|
32 |
|
|
|
39 |
|
|
|
61 |
|
(1) |
In Q1 2020, our new resource play, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified. |
(2) |
Includes expenditures on PP&E and E&E assets. |
In the third quarter of 2020 there were no net wells drilled, completed, and tied-in. For the nine months ended September 30, 2020 there were no net wells drilled or completed and two wells were tied-in and brought on production. In the third quarter of 2019, there were two wells drilled and on a year-to-date basis, there were two wells drilled and one well tied-in.
Future Capital Investment
Our 2020 Conventional capital investment is forecasted to be between $75 million and $85 million. This includes an incremental $30 million in the fourth quarter, relative to Conventional (previously Deep Basin) guidance, for a two-rig drilling program targeting low-risk, high-return development wells near our owned and operated natural gas plants to take advantage of an expected strengthening in commodity prices during the winter heating season. We continue to take a disciplined approach to the development of our Conventional assets. 2020 Guidance dated April 1, 2020 is available on our website at cenovus.com.
In the third quarter of 2020, we:
• |
Managed to economic crude oil runs of 382,000 barrels per day, lower than the third quarter of 2019 in response to the economic slowdown due to COVID-19; |
• |
Reported Operating Margin of negative $74 million, a decrease of $200 million compared with 2019, due to lower global crude oil and refined product pricing, which led to decreased market crack spreads and lower crude advantage, and decreased crude oil runs, partially offset by lower operating costs; and |
• |
Recorded an impairment charge of $450 million, as additional DD&A expense, associated with the Borger CGU. |
Financial Results
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 (1) |
|
|
2020 |
|
|
2019 (1) |
|
||||
Revenues |
|
1,569 |
|
|
|
2,420 |
|
|
|
4,706 |
|
|
|
7,958 |
|
Purchased Product |
|
1,444 |
|
|
|
2,026 |
|
|
|
4,170 |
|
|
|
6,622 |
|
Inventory Write-Down (Reversal) |
|
- |
|
|
|
16 |
|
|
|
233 |
|
|
|
24 |
|
Gross Margin |
|
125 |
|
|
|
378 |
|
|
|
303 |
|
|
|
1,312 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
197 |
|
|
|
255 |
|
|
|
624 |
|
|
|
698 |
|
(Gain) Loss on Risk Management |
|
2 |
|
|
|
(3 |
) |
|
|
(6 |
) |
|
|
(14 |
) |
Operating Margin |
|
(74 |
) |
|
|
126 |
|
|
|
(315 |
) |
|
|
628 |
|
Depreciation, Depletion and Amortization |
|
521 |
|
|
|
65 |
|
|
|
673 |
|
|
|
213 |
|
Segment Income (Loss) |
|
(595 |
) |
|
|
61 |
|
|
|
(988 |
) |
|
|
415 |
|
(1) |
The comparative period has been reclassified to conform with current period treatment of non-cash inventory write-downs and reversals. |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
24 |
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Crude Oil Capacity (Mbbls/d) |
|
495 |
|
|
|
482 |
|
|
|
495 |
|
|
|
482 |
|
Crude Oil Runs (Mbbls/d) |
|
382 |
|
|
|
465 |
|
|
|
383 |
|
|
|
438 |
|
Heavy Crude Oil |
|
154 |
|
|
|
185 |
|
|
|
154 |
|
|
|
174 |
|
Light/Medium |
|
228 |
|
|
|
280 |
|
|
|
229 |
|
|
|
264 |
|
Refined Products (Mbbls/d) |
|
397 |
|
|
|
485 |
|
|
|
396 |
|
|
|
463 |
|
Gasoline |
|
207 |
|
|
|
215 |
|
|
|
195 |
|
|
|
218 |
|
Distillate |
|
115 |
|
|
|
169 |
|
|
|
130 |
|
|
|
162 |
|
Other |
|
75 |
|
|
|
101 |
|
|
|
71 |
|
|
|
83 |
|
Crude Utilization (percent) |
|
77 |
|
|
|
96 |
|
|
|
77 |
|
|
|
91 |
|
(1) |
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent. |
On a 100 percent basis, the Refineries had total processing capacity re-rated on January 1, 2020 to 495,000 gross barrels per day of crude oil, including processing capability of up to 275,000 gross barrels per day of blended heavy crude oil. The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in the Refineries relative to the total capacity.
Crude oil runs and refined product output decreased in the third quarter as both Refineries continued crude rate reductions in response to the reduced demand and weak pricing for refined products due to COVID-19. In the third quarter of 2019, there were unplanned outages and the startup of planned turnaround activities at both Refineries in September 2019, partially offset by Wood River achieving a record monthly crude oil run rate in July 2019. For the three and nine months ended September 30, 2020, crude oil runs and refined product output decreased compared with the prior year, as the economic crude rate reductions in 2020 had a greater impact than planned and unplanned maintenance in 2019.
Crude-By-Rail Terminal
As announced in the first quarter, our crude-by-rail program continues to be suspended in response to the current market environment. The suspension was completed during the second quarter. In the three months ended September 30, 2020, we loaded an average of 8,753 barrels per day (no barrels per day of our volumes) from our Bruderheim crude-by-rail terminal compared with an average of 64,773 barrels per day (45,154 barrels per day of our volumes) in the third quarter of 2019. On a year-to-date basis, we loaded an average of 33,244 barrels per day (23,720 barrels per day of our volumes) from our Bruderheim crude-by-rail terminal compared with an average of 57,092 barrels per day (36,433 barrels per day of our volumes) in 2019.
Gross Margin
While market crack spreads are an indicator of margin from processing crude oil into refined products, the refining realized crack spread, which is the gross margin on a per-barrel basis, is affected by many factors, such as the variety of feedstock crude oil processed; refinery configuration and the proportion of gasoline, distillate and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the Refineries; and the cost of feedstock. Our feedstock costs are valued on a FIFO accounting basis.
In the three months ended September 30, 2020, Refining and Marketing gross margin decreased $253 million relative to the third quarter of 2019, primarily due to decreased market crack spreads and lower crude advantage as a result of lower global crude oil and refined product pricing, and decreased crude oil runs.
In the nine months ended September 30, 2020, Refining and Marketing gross margin decreased $1,009 million resulting from decreased market crack spreads and crude advantage as a result of lower global crude oil and refined product pricing, and reduced crude oil runs, partially offset by higher margins on refined products. Our gross margin was positively impacted by approximately $1 million and $4 million for the three and nine months ended September 30, 2020, respectively, due to the weakening of the Canadian dollar relative to the U.S. dollar.
In the three and nine months ended September 30, 2020, the cost of Renewable Identification Numbers (“RINs”) was $50 million and $119 million, respectively (2019 – $24 million and $73 million, respectively). RIN costs increased, primarily due to higher pricing, partially offset by lower volume obligations.
Inventory Write-Down (Reversal)
As a result of a decline in refined product and crude oil prices, inventory write-downs of $253 million were recorded related to our refined product and feedstock inventory in the first quarter of 2020. Subsequently we reversed
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
25 |
|
|
|
$20 million of product inventories still on hand due to improved refined product and crude oil prices. For the nine months ended September 30, 2019, we recorded inventory write-downs, net of reversals, of $24 million.
Operating Expense
For the three and nine months ended September 30, 2020, the primary drivers of operating expenses were labour, maintenance and utilities. Operating expenses decreased in the third quarter of 2020 primarily due to lower maintenance costs due to greater maintenance activity in 2019. Operating expenses decreased on a year-to-date basis primarily due to higher maintenance activity in 2019 and lower utility costs.
DD&A
Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from three to 60 years. The service lives of these assets are reviewed on an annual basis. ROU assets are depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. Refining and Marketing DD&A was $521 million and $673 million in the three and nine months ended September 30, 2020, respectively (2019 – $65 million and $213 million, respectively). The increase in DD&A is primarily due to an impairment charge of $450 million related to the Borger CGU.
Capital Investment
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Wood River Refinery |
|
41 |
|
|
|
41 |
|
|
|
96 |
|
|
|
96 |
|
Borger Refinery |
|
19 |
|
|
|
25 |
|
|
|
54 |
|
|
|
82 |
|
Marketing |
|
5 |
|
|
|
21 |
|
|
|
22 |
|
|
|
36 |
|
Capital Investment |
|
65 |
|
|
|
87 |
|
|
|
172 |
|
|
|
214 |
|
Capital expenditures in the three and nine months ended September 30, 2020 focused primarily on yield enhancement, reliability and maintenance projects, as well as storage infrastructure projects.
In 2020, we expect to invest between $270 million and $300 million and will continue to focus on refining reliability and maintenance, and yield enhancement projects. Our 2020 guidance dated April 1, 2020 is available on our website at cenovus.com.
In the three months ended September 30, 2020, our risk management activities resulted in:
• |
Unrealized risk management gains of $135 million (2019 – losses of $9 million) due to the realization of settled positions and changes in the commodity prices compared with the end of the prior quarter. This included unrealized losses of $3 million from cross currency interest swaps; and |
• |
A realized foreign exchange hedge gain of $1 million (2019 – loss of $1 million). |
On a year-to-date basis, our risk management activities resulted in:
• |
Unrealized risk management losses of $7 million (2019 – losses of $157 million) due to the realization of settled positions and changes in commodity prices compared with the prices at the end of the prior year; and |
• |
Realized foreign exchange risk management losses of $4 million (2019 – gain of $1 million and loss of $1 million on interest rate swap contracts). |
Transactions typically span across periods in order to execute the optimization strategy and these transactions reside across both realized and unrealized risk management.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
26 |
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
General and Administrative |
|
50 |
|
|
|
72 |
|
|
|
124 |
|
|
|
209 |
|
Onerous Contract Provisions |
|
1 |
|
|
|
(1 |
) |
|
|
- |
|
|
|
(8 |
) |
Finance Costs |
|
145 |
|
|
|
138 |
|
|
|
391 |
|
|
|
376 |
|
Interest Income |
|
(2 |
) |
|
|
(3 |
) |
|
|
(4 |
) |
|
|
(9 |
) |
Foreign Exchange (Gain) Loss, Net |
|
(159 |
) |
|
|
88 |
|
|
|
168 |
|
|
|
(265 |
) |
Re-measurement of Contingent Payment |
|
(31 |
) |
|
|
(17 |
) |
|
|
(97 |
) |
|
|
137 |
|
Research Costs |
|
3 |
|
|
|
6 |
|
|
|
8 |
|
|
|
16 |
|
(Gain) Loss on Divestiture of Assets |
|
(1 |
) |
|
|
3 |
|
|
|
- |
|
|
|
7 |
|
Other (Income) Loss, Net |
|
(17 |
) |
|
|
(11 |
) |
|
|
(60 |
) |
|
|
(4 |
) |
|
|
(11 |
) |
|
|
275 |
|
|
|
530 |
|
|
|
459 |
|
General and Administrative
Primary drivers of our general and administrative expenses were workforce costs, employee long-term incentive costs, and operating costs associated with our real estate portfolio. In the third quarter, general and administrative (“G&A”) expenses decreased $22 million compared with the same period of 2019 primarily due to lower employee long-term incentive costs as a result of the change in share price in the period. On a year-to-date basis, G&A expenses were $85 million lower primarily due to lower employee long-term incentive costs and operating costs associated with our real estate portfolio. Our guidance dated April 1, 2020 is available on our website at cenovus.com.
Finance costs increased by $7 million in the three months ended September 30, 2020 compared with 2019, due to higher long- and short-term borrowings and higher interest expense on lease liabilities from new contract additions in 2020 compared with 2019. On a year‑to‑date basis, finance costs increased by $15 million compared with 2019 due to a discount of $25 million on the repurchase of unsecured notes compared with $64 million in 2019, higher short-term borrowings during the period, and a higher interest expense on lease liabilities due to new contract additions in 2020 compared with 2019. This was partially offset by decreased interest on long‑term debt due to the lower weighted average interest rate on outstanding debt.
The weighted average interest rate on outstanding debt for the three and nine months ended September 30, 2020 was 4.8 percent (2019 – 5.2 percent and 5.1 percent, respectively).
Foreign Exchange
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Unrealized Foreign Exchange (Gain) Loss |
|
(140 |
) |
|
|
88 |
|
|
|
229 |
|
|
|
(560 |
) |
Realized Foreign Exchange (Gain) Loss |
|
(19 |
) |
|
|
- |
|
|
|
(61 |
) |
|
|
295 |
|
|
|
(159 |
) |
|
|
88 |
|
|
|
168 |
|
|
|
(265 |
) |
In the third quarter of 2020 and on a year-to-date basis, unrealized foreign exchange gains of $140 million and losses of $229 million, respectively, were recorded primarily as a result of the translation of our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar as at September 30, 2020 was stronger compared with June 30, 2020, resulting in unrealized gains and three percent weaker compared with December 31, 2019, resulting in unrealized losses.
Re-measurement of Contingent Payment
Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips Company and certain of its subsidiaries (“ConocoPhillips”) during the five years subsequent to the closing date of the acquisition from ConocoPhillips of their 50 percent interest in the FCCL Partnership on May 17, 2017 (“the Acquisition”), for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment is $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment.
The contingent payment is accounted for as a financial option. The fair value of $46 million as at September 30, 2020 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. For the three and nine months ended September 30, 2020, a non-cash re‑measurement gain of $31 million and $97 million, respectively, was recorded.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
27 |
|
|
|
Average WCS forward pricing for the remaining term of the contingent payment is $37.41 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately $36.50 per barrel and $39.20 per barrel.
Other (Income) Loss, Net
The Government of Canada passed the CEWS as part of its COVID-19 Economic Response Plan. The program is effective from March 15, 2020 to the summer of 2021. For the three and nine months ended September 30, 2020, we recorded $9 million and $40 million, respectively, in other income from the CEWS program.
DD&A
Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements, office furniture, and certain ROU assets. Costs associated with corporate assets are depreciated on a straight‑line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. ROU assets (real estate assets) are depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. DD&A in the three months ended September 30, 2020 was $27 million (2019 – $24 million) and $104 million on a year‑to‑date basis (2019 – $81 million).
Income Tax
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|||||
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
(1 |
) |
|
|
10 |
|
|
|
(3 |
) |
|
|
22 |
|
United States |
|
- |
|
|
|
(4 |
) |
|
|
1 |
|
|
|
1 |
|
Current Tax Expense (Recovery) |
|
(1 |
) |
|
|
6 |
|
|
|
(2 |
) |
|
|
23 |
|
Deferred Tax Expense (Recovery) |
|
(177 |
) |
|
|
46 |
|
|
|
(656 |
) |
|
|
(790 |
) |
Total Tax Expense (Recovery) |
|
(178 |
) |
|
|
52 |
|
|
|
(658 |
) |
|
|
(767 |
) |
Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and with consideration of the current economic environment, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.
For the three and nine months ended September 30, 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU and current period operating losses that will be carried forward, excluding unrealized foreign exchange gains and losses on long-term debt.
In the nine months ended September 30, 2019, the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to eight percent over four years. As a result, we recorded a deferred income tax recovery of $663 million. In addition, we recorded a deferred income tax recovery of $387 million due to an internal restructuring of our U.S. operations resulting in a step-up in the tax basis of our refining assets and current tax expense of $23 million was recorded on current year operations, net of prior year losses.
Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and the actual amounts subsequently reported on the tax returns, and other permanent differences.
Capital Investment
Capital expenditures of $51 million for 2020 focused primarily on supporting investments in technology and infrastructure to modernize our workplace, improve our cost structure and reduce costs and risk.
In 2020, we expect to invest up to $55 million. Our guidance dated April 1, 2020 is available on our website at cenovus.com.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
28 |
|
|
|
LIQUIDITY AND CAPITAL RESOURCES
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|||||
Cash From (Used in) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
732 |
|
|
|
834 |
|
|
|
23 |
|
|
|
2,545 |
|
Investing Activities |
|
(136 |
) |
|
|
(343 |
) |
|
|
(663 |
) |
|
|
(966 |
) |
Net Cash Provided (Used) Before Financing Activities |
|
596 |
|
|
|
491 |
|
|
|
(640 |
) |
|
|
1,579 |
|
Financing Activities |
|
(322 |
) |
|
|
(100 |
) |
|
|
901 |
|
|
|
(1,888 |
) |
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
(22 |
) |
|
|
(18 |
) |
|
|
(43 |
) |
|
|
(35 |
) |
Increase (Decrease) in Cash and Cash Equivalents |
|
252 |
|
|
|
373 |
|
|
|
218 |
|
|
|
(344 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Cash and Cash Equivalents |
|
|
|
|
|
|
|
|
|
404 |
|
|
|
186 |
|
Debt |
|
|
|
|
|
|
|
|
|
7,934 |
|
|
|
6,699 |
|
As at September 30, 2020, we were in compliance with all of the terms of our debt agreements.
Cash From (Used in) Operating Activities
For both the three and nine months ended September 30, 2020, cash generated by operating activities decreased mainly due to lower Operating Margin, partially offset by higher other income due to CEWS, and lower current taxes, as discussed in the Corporate and Eliminations section of this MD&A, and changes in non‑cash working capital, as discussed in the Operating and Financial Results section of this MD&A.
Excluding risk management assets and liabilities and the current portion of the contingent payment, our working capital was $754 million at September 30, 2020 compared with $839 million at December 31, 2019.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used in) Investing Activities
Cash used in investing activities for the three and nine months ended September 30, 2020 was lower compared with 2019 primarily due to decreased capital investment.
Cash From (Used in) Financing Activities
In the third quarter of 2020, cash proceeds from the issuance of US$1.0 billion in 5.375 percent senior unsecured notes due in 2025 and cash on hand were used to repay $1.4 billion of borrowings on our committed credit facility and $159 million of short-term borrowings.
Total debt, including short-term borrowings, as at September 30, 2020 was $7,934 million (December 31, 2019 – $6,699 million). We have no principal payments due on our long-term debt until August 2022.
During the nine months ended September 30, 2020, we:
• |
Repurchased US$100 million of unsecured notes for cash of US$81 million in the first quarter; |
• |
Borrowed $1.4 billion on our credit facility in the second quarter; and |
• |
Used the proceeds from the issuance of US$1.0 billion in 5.375 percent senior unsecured notes due in 2025 to repay $1.4 billion of borrowings on our committed credit facility in the third quarter. |
During the nine months ended September 30, 2019, we repaid US$1.3 billion of unsecured notes for cash consideration of US$1.2 billion ($1.6 billion).
Dividends
On April 2, 2020 we announced the temporary suspension of our dividend in response to the low global crude oil price environment. The continued suspension of our dividend resulted in no dividends paid in the third quarter of 2020 (2019 – $0.05 per common share or $60 million). In the nine months ended September 30, 2020, we paid dividends of $0.0625 per common share or $77 million (2019 – $0.15 per common share or $183 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
29 |
|
|
|
Available Sources of Liquidity
The following sources of liquidity are available at September 30, 2020:
($ millions) |
Term |
|
|
Amount Available |
|
|
Cash and Cash Equivalents |
Not applicable |
|
|
|
404 |
|
Committed Credit Facilities |
|
|
|
|
|
|
Revolving Credit Facility – Tranche A |
November 2023 |
|
|
|
3,300 |
|
Revolving Credit Facility – Tranche B |
November 2022 |
|
|
|
1,200 |
|
Liquidity Facility |
April 2021 |
|
|
|
1,100 |
|
Uncommitted Demand Facilities |
|
|
|
|
|
|
Cenovus Energy Inc. |
Not applicable |
|
|
|
600 |
|
WRB Refining LP (Cenovus's proportionate share) |
Not applicable |
|
|
|
63 |
|
In light of the current challenging economic conditions, we expect to fund our near-term cash requirements through cash from operating activities and prudent use of our balance sheet capacity including draws on our committed credit facilities and our uncommitted bilateral demand lines and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings and DBRS Limited and re-establishing investment grade ratings at both Moody’s Investor Service (“Moody’s”) and Fitch Ratings (“Fitch”). The cost and availability of borrowing, and access to sources of liquidity and capital is dependent on current credit ratings as determined by independent rating agencies and market conditions.
We have total committed credit facilities of $5.6 billion. We have a committed revolving credit facility in place that consists of a $1.2 billion tranche maturing on November 30, 2022 and a $3.3 billion tranche maturing November 30, 2023. During the second quarter, we added a committed credit facility with capacity of $1.1 billion, with a term of 364 days that is renewable for one year at our request and upon approval by the lenders, to further support our financial resilience in the current market environment. As at September 30, 2020, no amounts were drawn on our committed credit facilities.
Uncommitted Demand Facilities
Cenovus has uncommitted demand facilities of $1.6 billion in place, of which $600 million may be drawn for general purposes or the full amount can be available to issue letters of credit. As at September 30, 2020, the Company had drawn no amounts (December 31, 2019 - $nil) on these facilities and there were outstanding letters of credit aggregating to $457 million (December 31, 2019 - $364 million).
WRB Refining LP has uncommitted demand facilities of US$300 million (the Company’s proportionate share - US$150 million) available to cover short-term working capital requirements. As at September 30, 2020, US$205 million was drawn on the facilities, of which US$103 million ($137 million) was the Company’s proportionate share (December 31, 2019 – $nil).
Base Shelf Prospectus
Cenovus has in place a base shelf prospectus which expires in October 2021. During the third quarter, we completed the issuance of US$1.0 billion in 5.375 percent senior unsecured notes due in 2025 under our short form base shelf prospectus. As at September 30, 2020, US$4.0 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. We define Capitalization as Net Debt plus Shareholders’ Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense, DD&A, E&E Write-down, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, and other income (loss), net, calculated on a trailing twelve-month basis. These measures are used to steward our overall debt position and as measures of our overall financial strength.
|
September 30, 2020 |
|
|
December 31, 2019 |
|
|
||
Net Debt to Capitalization (1) (percent) |
|
31 |
|
|
|
25 |
|
|
Net Debt to Adjusted EBITDA (times) |
8.4x |
|
|
1.6x |
|
|
(1) |
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity. |
Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may periodically be above the target due to factors such as persistently low commodity prices. Our objective is to
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
30 |
|
|
|
maintain a high level of capital discipline and manage our capital structure to help ensure the Company has sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares. We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenants as defined in our committed credit facility agreements.
As at September 30, 2020, Cenovus’s Net Debt to Adjusted EBITDA was 8.4 times. Net Debt to Adjusted EBITDA increased compared with December 31, 2019 as a result of a weaker Canadian dollar, an increase in our borrowings, as mentioned in the Cash From (Used In) Financing Activities above, and a reduction in our trailing twelve-month adjusted EBITDA.
Under the committed credit facilities, Cenovus is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. We were well below this limit at September 30, 2020.
Additional information regarding our financial measures and capital structure can be found in the notes to the interim Consolidated Financial Statements.
Share Capital and Stock-Based Compensation Plans
As at September 30, 2020, there were approximately 1,229 million common shares outstanding (2019 – 1,229 million common shares).
Refer to Note 26 of the interim Consolidated Financial Statements for more details on our Stock Option Plan and our Performance Share Unit, Restricted Share Unit and Deferred Share Unit Plans.
As at September 30, 2020 |
|
Units Outstanding (thousands) |
|
|
Units Exercisable (thousands) |
|
||
Common Shares (1) |
|
|
1,228,870 |
|
|
N/A |
|
|
Stock Options |
|
|
30,795 |
|
|
|
20,576 |
|
Other Stock-Based Compensation Plans |
|
|
18,730 |
|
|
|
1,502 |
|
(1) |
ConocoPhillips continued to hold 208 million common shares issued as partial consideration related to the Acquisition. |
Capital Investment Decisions
Our 2020 capital program is forecast to be between $750 million and $850 million. Planned capital spending has been reduced from 2019 in order to maintain the strength of our balance sheet in response to the significant decline in world benchmark crude oil prices. Our 2020 capital allocation priorities demonstrate the flexibility in our business plan while remaining focused on committed capital priorities including safe and reliable operations and sustaining and maintenance capital for our existing business operations.
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
($ millions) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Adjusted Funds Flow (1) |
|
414 |
|
|
|
928 |
|
|
|
(194 |
) |
|
|
3,015 |
|
Total Capital Investment |
|
148 |
|
|
|
294 |
|
|
|
599 |
|
|
|
859 |
|
Free Funds Flow (1) (2) |
|
266 |
|
|
|
634 |
|
|
|
(793 |
) |
|
|
2,156 |
|
Cash Dividends |
|
- |
|
|
|
60 |
|
|
|
77 |
|
|
|
183 |
|
|
|
266 |
|
|
|
574 |
|
|
|
(870 |
) |
|
|
1,973 |
|
(1) |
The comparative period has been reclassified to conform with current period treatment of non-cash inventory write-downs and reversals. |
(2) |
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment. |
We continue to challenge our cost structure and have adjusted our discretionary capital plans in 2020, including temporarily suspending our quarterly cash dividend. This should allow the Company to fund a portion of its capital program with internally generated cash flows, cash on hand and the prudent use of our balance sheet capacity including draws on our credit lines.
Contractual Obligations and Commitments
Cenovus has obligations for goods and services entered into in the normal course of business. Obligations are primarily related to transportation agreements, our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less than one year are excluded. For further information, see the notes to the September 30, 2020 interim Consolidated Financial Statements and December 31, 2019 Consolidated Financial Statements.
As at September 30, 2020, total commitments were $23 billion, of which $22 billion are for various transportation and storage commitments. Transportation commitments include $14 billion (2019 – $13 billion) that are subject to regulatory approval or have been approved but are not yet in service. Terms are up to 20 years subsequent to the date of commencement and should help align with the Company’s future transportation requirements with anticipated production growth.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
31 |
|
|
|
We continue to focus on mid-term strategies to broaden market access for our crude oil production. We continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil.
As at September 30, 2020, there were outstanding letters of credit aggregating $457 million issued as security for performance under certain contracts (December 31, 2019 – $364 million).
Legal Proceedings
We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements.
Contingent Payment
In connection with the Acquisition and related to our Oil Sands production, we agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. As at September 30, 2020, the estimated fair value of the contingent payment was estimated to be $46 million. As at September 30, 2020, no amount was payable under the agreement. See the Corporate and Eliminations section of this MD&A for more details.
RISK MANAGEMENT AND RISK FACTORS
For a full understanding of the risks that impact us, the following discussion should be read in conjunction with the Risk Management and Risk Factors section of our 2019 annual MD&A.
We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition, results of operations and cash flows, which may reduce or restrict our ability to pursue our strategic priorities, respond to changes in our operating environment, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and may materially affect the market price of our securities.
The following provides an update on our risks.
Pandemic Risk
On March 11, 2020 the World Health Organization declared COVID-19 a pandemic indicating the sustained risk of global spread of the disease. Governments and health authorities around the world have implemented a wide variety of measures to reduce the spread of the virus, including travel restrictions, business closures, stay-at-home orders, physical distancing measures and event cancellations. The effect of these measures has been a significant slow-down in global economic activity that has reduced the demand for crude oil and natural gas products and contributed to a sharp decline in global crude oil and natural gas prices. While economies have started to re-open, a resurgence in cases of COVID-19 has occurred in certain locations and the risk of a resurgence in other locations remains high. This creates ongoing uncertainty that could result in restrictions on movement and businesses being re-imposed or imposed on a stricter basis, which could negatively impact demand for commodities and commodity prices and negatively impact our business, results of operations and financial condition. It is impossible at this point to predict precisely the duration or extent of the impacts of the COVID-19 pandemic on Cenovus's employees, customers, partners and business or when economic activity will normalize.
The COVID-19 pandemic may increase our exposure to, and magnitude of, each of the risks identified in the Risk Management and Risk Factors section of our 2019 annual MD&A. Our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund dividend payments and/or business plans may, in particular, without limitation, be adversely impacted as a result of the pandemic and/or decline in commodity prices as a result of:
• |
The shut-down of facilities or the delay or suspension of work on major capital projects due to workforce disruptions or labour shortages caused by workers becoming infected with COVID-19, or government or health authority mandated restrictions on travel by workers or closure of facilities, workforce camps or worksites; |
• |
Suppliers and third-party vendors experiencing similar workforce disruptions or being ordered to cease operations; |
• |
Reduced cash flows resulting in less funds from operations being available to fund our capital expenditure budget; |
• |
Reduced commodity prices resulting in a reduction in the volumes and value of our reserves. See "Commodity Prices" below; |
• |
Crude oil storage constraints resulting in the curtailment or shutting in of production; |
• |
Counterparties being unable to fulfill their contractual obligations to us on a timely basis or at all; |
• |
The inability to deliver products to customers or otherwise get products to market caused by border restrictions, road or port closures or pipeline shut-ins, including as a result of pipeline companies suffering workforce disruptions or otherwise being unable to continue to operate; |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
32 |
|
|
|
• |
The capabilities of our information technology systems and the potential heightened threat of a cyber-security breach arising from the number of employees working remotely; and |
• |
Our ability to obtain additional capital including, but not limited to, debt and equity financing being adversely impacted as a result of unpredictable financial markets, commodity prices and/or a change in market fundamentals. |
The extent to which COVID-19 impacts our business, results of operations and financial condition will depend on future developments, which are highly uncertain and are difficult to predict, including, but not limited to, the duration and spread of the pandemic, its severity, the actions taken to contain COVID-19 or treat its impact, and how quickly and to what extent normal economic and operating conditions can resume. The potential impacts of COVID-19 to our business, results of operations and financial condition could be more significant in upcoming periods as compared with the first three-quarters of 2020. Even after the COVID-19 pandemic has subsided, we may continue to experience materially adverse impacts to our business as a result of the pandemic's global economic impact.
There are no comparable recent events that provide guidance as to the effect the spread of COVID-19 as a global pandemic may have, and, as a result, the ultimate impact of the outbreak is highly uncertain and subject to change. Management does not yet know the full extent of the impacts on our business and operations or the global economy as a whole. The situation is changing rapidly and future impacts may materialize that are not yet known.
We are taking proactive steps to protect the health and safety of our staff and the continuity of our business in response to the COVID-19 pandemic. To deter COVID-19 from spreading in any of our workplaces, we implemented physical distancing measures, and had directed the vast majority of our office staff and certain non-essential field staff to work from home. Following the guidance of health officials, mandatory self-quarantine policies, travel restrictions, screening and enhanced cleaning and sanitation measures have been put in place. Our staff have committed to adhering to the new procedures. We also have a comprehensive Business Continuity Plan to ensure continued safe and reliable operations in the event of a COVID-19 outbreak at any of our workplaces. Earlier this month, we lifted our mandatory work from home measure to open our modified workspaces in the Calgary offices to staff again, with workplace safety plans and protocols in place. Increases in staff levels at sites and offices has been and will continue to be achieved in accordance with guidance received from the Federal and Provincial governments and public health officials.
Excess Crude Oil Supply Risk
It is not known how long low commodity price conditions will continue, however if the situation continues or worsens (and if it is exacerbated further by the impact of COVID-19) and global crude oil prices remain low for a prolonged period, among other things, our production, project development, profitability, cash flows, ability to access additional capital, and securities trading price could be adversely impacted. While OPEC members agreed to certain production cuts through April 2022 amid the global demand reduction caused by the pandemic, there can be no assurances that OPEC members and other oil exporting nations will continue to agree to actions to stabilize oil prices. Uncertainty regarding the future actions of such nations may lead to increased commodity price volatility. See "Commodity Prices" below.
Commodity Prices
Fluctuations in commodity prices, associated price differentials and refining margins impact our financial condition, results of operations, cash flows, growth, access to capital and cost of borrowing.
We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts, market access commitments and generally through our access to committed credit facilities. Financial instruments undertaken within our refining business by the operator, Phillips 66, are primarily for purchased product. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 27 and 28 of the interim Consolidated Financial Statements.
Additionally, the factors discussed under the headings "Pandemic Risk" and "Excess Crude Oil Supply Risk" could continue to negatively impact commodity prices. If crude oil and natural gas prices continue to remain at low levels for an extended period of time, or if the costs of development of our resources significantly increases, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected. See "Risk Management and Risk Factors – Financial Risks – Commodity Prices" in our 2019 annual MD&A.
Risks Associated with Derivative Financial Instruments
Financial instruments expose us to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Credit Policy.
Financial instruments also expose us to the risk of a loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical transaction. Financial instruments may limit the benefit to us if commodity prices, interest or foreign exchange rates change. These risks are managed through hedging limits authorized according to our Market Risk Management Policy.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
33 |
|
|
|
Impact of Financial Risk Management Activities
|
Three Months Ended September 30, |
|
|||||||||||||||||
|
2020 |
|
|
2019 |
|
||||||||||||||
($ millions) |
Realized |
|
Unrealized |
|
Total |
|
|
Realized |
|
Unrealized |
|
Total |
|
||||||
Crude Oil |
|
137 |
|
|
(135 |
) |
|
2 |
|
|
|
(7 |
) |
|
9 |
|
|
2 |
|
Refining |
|
2 |
|
|
(3 |
) |
|
(1 |
) |
|
|
(3 |
) |
|
- |
|
|
(3 |
) |
Cross Currency Interest Rate |
|
- |
|
|
3 |
|
|
3 |
|
|
|
- |
|
|
- |
|
|
- |
|
Foreign Exchange |
|
(1 |
) |
|
- |
|
|
(1 |
) |
|
|
1 |
|
|
- |
|
|
1 |
|
(Gain) Loss on Risk Management |
|
138 |
|
|
(135 |
) |
|
3 |
|
|
|
(9 |
) |
|
9 |
|
|
- |
|
Income Tax Expense (Recovery) |
|
(36 |
) |
|
33 |
|
|
(3 |
) |
|
|
2 |
|
|
(1 |
) |
|
1 |
|
(Gain) Loss on Risk Management, After Tax |
|
102 |
|
|
(102 |
) |
|
- |
|
|
|
(7 |
) |
|
8 |
|
|
1 |
|
|
Nine Months Ended September 30, |
|
|||||||||||||||||
|
2020 |
|
|
2019 |
|
||||||||||||||
($ millions) |
Realized |
|
Unrealized |
|
Total |
|
|
Realized |
|
Unrealized |
|
Total |
|
||||||
Crude Oil |
|
228 |
|
|
8 |
|
|
236 |
|
|
|
38 |
|
|
151 |
|
|
189 |
|
Refining |
|
(6 |
) |
|
(1 |
) |
|
(7 |
) |
|
|
(14 |
) |
|
1 |
|
|
(13 |
) |
Interest Rate |
|
- |
|
|
- |
|
|
- |
|
|
|
1 |
|
|
7 |
|
|
8 |
|
Cross Currency Interest Rate |
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
Foreign Exchange |
|
4 |
|
|
- |
|
|
4 |
|
|
|
(1 |
) |
|
(2 |
) |
|
(3 |
) |
(Gain) Loss on Risk Management |
|
226 |
|
|
7 |
|
|
233 |
|
|
|
24 |
|
|
157 |
|
|
181 |
|
Income Tax Expense (Recovery) |
|
(55 |
) |
|
(2 |
) |
|
(57 |
) |
|
|
(7 |
) |
|
(38 |
) |
|
(45 |
) |
(Gain) Loss on Risk Management, After Tax |
|
171 |
|
|
5 |
|
|
176 |
|
|
|
17 |
|
|
119 |
|
|
136 |
|
For Cash Flow derivatives, we incurred a realized loss due to the settlement of benchmark prices relative to our risk management contract prices. For Optimization derivatives, the realized loss was from our decisions to store rather than sell our physical crude oil and condensate volumes. Cenovus uses its marketing and transportation initiatives, including storage and pipeline assets to optimize product mix, delivery points, transportation commitments and customer diversification, to inventory physical positions. At the time we make the decision to store crude oil and condensate volumes, the prices available for future periods we plan to sell in can be locked in and the improved margin realized in the future periods, which are superior to short-term prices. The risk management gains and losses offset corresponding fluctuations in revenues generated from the underlying physical sales.
Unrealized gains of $135 million in the three months ended September 30, 2020 and unrealized losses of $8 million on a year-to-date basis, were recorded on our crude oil financial instruments primarily due to changes in commodity prices compared with prices at the end of the prior quarter and prior year, respectively, and the realization of settled positions.
Transactions typically span across periods in order to execute the optimization strategy, and these transactions reside across both realized and unrealized risk management.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES
Management is required to make estimates and assumptions and use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements.
Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements.
Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised.
The full extent of the impact of COVID-19 on our operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
34 |
|
|
|
COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by Management in the preparation of its financial results.
A full list of the key sources of estimation uncertainty can be found in our annual Consolidated Financial Statements for the year ended December 31, 2019. The outbreak of COVID-19 and current market conditions have increased the complexity of estimates and assumptions used to prepare Consolidated Financial Statements, particularly related to the following key sources of estimation uncertainty:
• |
Recoverable Amounts |
Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. The severe drop in commodity prices, including refined product, and the decline in market crack spreads due to reasons noted above, have increased the risk of measurement uncertainty in determining the recoverable amounts, especially estimating economic crude oil and natural gas reserves and estimating forward commodity prices.
• |
Decommissioning Costs |
Provisions are recorded for the future decommissioning and restoration of our upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of a liability and to estimate the future amount of the liability and uses a credit-adjusted discount rate to present value the estimated future cash flows required to settle the obligation. Market volatility has increased the measurement uncertainty inherent in determining the appropriate credit-adjusted discount rate that is used in the estimation of decommissioning liabilities.
• |
Income Tax Provisions |
Income taxes on earnings or loss in the interim periods are accrued using the income tax rate that would be applicable to the expected total annual earnings or loss. There is increased measurement uncertainty related to the expected total annual earnings or expected earnings due to the reduced demand and fluctuation of commodity prices as a result of COVID-19.
Changes to these assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.
Changes in Accounting Policies
There were no new or amended accounting standards or interpretations adopted during the nine months ended September 30, 2020.
New Accounting Standards and Interpretations not yet Adopted
A number of new standards, amendments to accounting standards and interpretations were effective beginning on or after January 1, 2020. There were no new or amended accounting standards or interpretations issued during the nine months ended September 30, 2020 that are expected to have a material impact on our interim Consolidated Financial Statements.
There have been no changes to internal control over financial reporting (“ICFR”) during the three months ended September 30, 2020 that have materially affected, or are reasonably likely to materially affect ICFR.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The following outlook commentary is focused on the next twelve months.
We expect the remainder of 2020 and much of 2021 to be a challenging time for our industry and the global economy in general due to the impacts of COVID-19. We expect continued crude oil and refined products demand and price recovery over the longer term as economies reopen and rebound from the negative impacts of the pandemic. However, with the continued uncertainty around COVID-19 and the scale of resurgence of COVID-19
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
35 |
|
|
|
cases, we anticipate crude oil and refined products demand to be volatile throughout 2020 and into 2021 with recovery dependent on the success of economic relaunches. We continue to anticipate that an increase in demand for refined products, particularly motor fuels, will be an early indicator of recovery from the impact of COVID-19. Our top priority will be to maintain the strength of our balance sheet. We have ample liquidity, top-tier assets which we are able to effectively manage to respond to price signals, one of the lowest cost structures in the industry and have demonstrated our ability to reduce discretionary capital, all of which should allow us to continue to adapt to these challenges.
We continue to monitor the overall market dynamics amidst the COVID-19 situation in assessing how we manage our Oil Sands production levels. Our assets can respond to market signals and ramp up production to produce above government mandated production curtailment levels dependent on the availability of production credits. This includes the potential to ramp up our temporarily suspended crude-by-rail program to generate Special Production Allowance (“SPA”) program curtailment relief or purchase third-party credits. Our decisions around production levels will be focused on maximizing the value we receive for our products. We expect our 2020 annual Oil Sands production to average between 350,000 barrels per day and 400,000 barrels per day.
We continue to look for additional opportunities to reduce operating, capital, and G&A spending and increase our margins through strong operating performance and cost leadership, while focusing on safe and reliable operations. Proactively managing our market access commitments and opportunities assists with our goal of reaching a broader customer base to secure a higher sales price for our crude oil.
Given the challenges faced by our industry and the global economy, achieving cumulative free funds flow of approximately $11 billion through 2024, as disclosed in our news release dated October 2, 2019 in respect of our five-year business plan, is uncertain and continues to be evaluated, and may be impacted by future events.
Commodity Prices Underlying our Financial Results
Our crude oil pricing outlook is influenced by the following:
• |
We expect the general outlook for light crude oil prices will be tied primarily to the supply and demand response to the current uncertain price environment, the impact of oversupply, and global demand impacts amid COVID-19 concerns; |
• |
Crude oil price volatility is expected to continue due to crude demand destruction as a result of COVID-19 and the pace and timing of recovery; |
• |
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts; |
• |
We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply cuts are sustained, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the Trans Mountain Expansion and Keystone XL projects, and the level of crude-by-rail activity; and |
• |
We expect refining market crack spreads in 2020 to remain weak relative to previous years as a result of significantly reduced refined products demand due to COVID-19. Refining market crack spreads are expected to continue to fluctuate, adjusting for seasonal trends and refining run cuts in North America. |
Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel, solvent and blending requirements at our Oil Sands operations.
|
|
Natural gas prices have been challenged due to weaker demand as a result of COVID-19, but the forward curve is showing that the market expects AECO prices to rebound into 2021. Seasonal demand is expected to support pricing in the fourth quarter of 2020. Production declines from both associated gas and dry gas, along with rebounding U.S. demand and liquified natural gas exports should tighten North American gas fundamentals further in 2021 and result in stronger prices than 2020 on an annual basis.
We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, and emerging macro‑economic factors. The Bank of Canada lowered its benchmark lending rate twice in 2020 to address the impacts of COVID-19.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
36 |
|
|
|
Our exposure to light-heavy crude oil price differentials is composed of both a global light-heavy component as well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of light-heavy crude oil price differentials through the following:
• |
Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets; |
• |
Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products; |
• |
Marketing agreements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; |
• |
Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil price differentials; and |
• |
Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions related to our exposures. |
Key Priorities For 2020
In the current low commodity price environment, we continue to focus on maintaining balance sheet strength and liquidity. Enhancing our financial resilience and flexibility while continuing to deliver safe and reliable operations will continue to be a top priority during these uncertain times.
Our corporate strategy remains unchanged, focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We expect to remain focused on disciplined capital investment, improved market access, and continued cost leadership to achieve margin improvement and environmental benefits.
Maintaining Financial Resilience
We have top-tier assets, one of the lowest cost structures in our industry and a strong balance sheet, all of which position us to withstand the challenges of the current market environment. Our capital planning process is flexible, and spending can be reduced in response to commodity prices and other economic factors so we can maintain our financial resilience. Our financial framework and flexible business plan allow multiple options to manage our balance sheet. We will continue to assess our spending plans on a regular basis while closely monitoring crude oil prices for the remainder of 2020 and into 2021.
Disciplined Capital Investment
As a result of the collapse of oil prices and COVID-19, we updated our 2020 guidance on April 1, 2020. We anticipate capital investment to be between $750 million and $850 million, the majority of which will be directed towards sustaining oil sands production and refining operations. We will continue to be disciplined with our capital. Our Oil Sands production is expected to range between 350,000 and 400,000 barrels per day for the remainder of 2020.
As at September 30, 2020, our Net Debt position was $7.5 billion. We expect to fund our near-term cash requirements through cash from operating activities, prudent use of our balance sheet capacity including draws on our credit and demand facilities, management of our asset portfolio and other corporate and financial opportunities that may be available to us. Through a combination of cash on hand and available capacity on our committed credit facilities and demand facilities, we have approximately $6.6 billion of liquidity. In addition, WRB has available capacity of approximately $63 million, for Cenovus’s proportionate share, on its demand facilities.
We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings and DBRS Limited and re-establishing investment grade ratings at Moody’s and Fitch.
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
37 |
|
|
|
Cenovus had based its ability to provide a sustainable dividend from free funds flow based on a WTI price environment of US$45.00 per barrel and taking into consideration our balance sheet strength. In the context of commodity price forecasts and economic, market and business conditions in the oil and gas industry, our quarterly dividend remains temporarily suspended.
Market Access
Market access constraints for Canadian crude oil production continue to be challenging. Our strategy is to maintain firm transportation commitments through a combination of pipelines, rail and marine. We expect to supplement firm capacity with active blending, storage, sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce. We have completed the temporary ramp down of our crude-by-rail program but expect to ramp it back up when the underlying pricing fundamentals support its continuation.
Cost Leadership
On April 1, 2020 we updated our guidance. We reduced our planned 2020 capital investment and are forecasting operating cost reductions of about $100 million and G&A cost reductions of about $50 million compared with our initial 2020 capital budget released in December 2019. We will continue to look for ways to improve efficiencies across Cenovus to drive incremental capital, operating and G&A cost reductions.
Oil and Gas Information
The estimates of reserves were prepared effective December 31, 2019 by independent qualified reserves evaluators (“IQREs”), based on the COGE Handbook and in compliance with the requirements of NI 51-101. Estimates are presented using an average of three IQREs January 1, 2020 price forecasts. For additional information about our reserves and other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended December 31, 2019.
Barrels of Oil Equivalent – natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six 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.
Forward-looking Information
This document 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 U.S. 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 we believe 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 “aim”, “anticipate”, “believe”, “can be”, “capacity”, “committed”, “commitment”, “continue”, “could”, “drive”, “enhance”, “ensure”, “estimate”, “expect”, “focus”, “forecast”, “forward”, “future”, “guidance”, “maintain”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “priority”, “re-establishing”, “strategy”, “should”, “target”, “will”, or similar expressions and includes suggestions of future outcomes, including statements about: strategy and related milestones; schedules and plans; anticipated receipt of required regulatory, court and securityholder approvals for the Husky Transaction and other customary closing conditions; focus on maximizing shareholder value through cost leadership and realizing the best margins for our products; maintaining liquidity and preserving a resilient balance sheet by reducing spending, while maintaining safe and reliable operations; longer-term focus on sustainably growing shareholder returns and reducing Net Debt as well as continuing to integrate ESG considerations into our business plan; maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility; evaluating disciplined investment in our portfolio against dividends, share repurchases and achieving and maintaining the optimal debt level while targeting investment grade status; focusing investment on areas where we believe we have the greatest competitive advantage; plan to achieve our strategy by leveraging our strategic focus areas including our oil sands, conventional oil and natural gas assets, marketing, transportation and refining portfolio, and our people; our reduced 2020 capital investment plan, operating cost reductions and G&A reductions enhances our financial resilience and financial capability to maintain our base business, deliver safe and reliable operations and to continue to challenge our cost structure in the face of these unprecedented conditions; ample liquidity and runway to sustain operations through a prolonged market downturn; anticipated volatility of demand and crude oil prices through 2020 and into 2021 as a result of continued uncertainty around COVID-19, with crude oil and refined
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
38 |
|
|
|
products demand and recovery dependent on the success of economic relaunches and the overall supply and demand balance; maintaining a high level of capital discipline and managing our capital structure to help ensure the Company has sufficient liquidity through all stages of the economic cycle; demand for refined product being an early indicator of recovery from the impact of COVID-19; increases in staff levels at sites and offices will continue to be achieved in accordance with guidance received from the Federal and Provincial governments and public health officials; expected timing for oil sands expansion phases projections for 2020 and future years and our plans and strategies to realize such projections; expectations to ramp up crude-by-rail program when the underlying pricing fundamentals support its continuation; potential to ramp up crude-by-rail program to generate SPAs or purchase third-party credits to produce above curtailment; the reduction of transportation costs caused by the temporary suspension of the crude-by-rail program; reaching a broader customer base; forecast exchange rates and trends; future opportunities for oil and natural gas development; forecast operating and financial results, including forecast sales prices, costs and cash flows; our ability to satisfy payment obligations as they become due; priorities for and approach to capital investment decisions or capital allocation, including decisions pertaining to new projects and phases; planned capital expenditures, including the amount, timing and funding sources thereof; all statements with respect to our 2020 guidance estimates; expected future production, including the timing, stability or growth thereof; our ability to manage our production well rates in response to pipeline capacity constraints, storage constraints, mandated production curtailments and crude oil price differentials; the impact of the Government of Alberta’s mandatory production curtailment; our ability to take steps to partially mitigate against wider WTI and WCS price differentials; our expectation that the general outlook for light crude oil prices will be tied primarily to the supply and demand response to the current uncertain price environment, the impact of oversupply, and global demand impacts amid COVID-19 concerns; our expectation that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply cuts are sustainable, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the Trans Mountain Expansion and Keystone XL projects, and the level of crude-by-rail activity; our expectation that in 2020 refining market crack spreads will remain weak relative to previous years as a result of significantly reduced refined products demand due to COVID-19; our expectation that our capital investment and near-term cash requirements will be funded through cash from operating activities and prudent use of our balance sheet capacity including draws on our credit and demand facilities, management of our asset portfolio and other corporate and financial opportunities that may be available to us; statements about our debt level as we manage through the low commodity price environment; expected reserves; focus on mid-term strategies to broaden market access for our crude oil production; supporting proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil; impact on alignment of transportation and storage commitments and production growth; all statements related to government royalty regimes applicable to Cenovus, which regimes are subject to change; our ability to preserve our financial resilience and various plans and strategies with respect thereto; our priorities, including for 2020; future impact of regulatory measures; forecast commodity prices, differentials and trends and expected impact; potential impacts of various risks, including those related to commodity prices and climate change; the potential effectiveness of our risk management strategies; new accounting standards, the timing for the adoption thereof, and anticipated impact on the Consolidated Financial Statements; the availability and repayment of our credit facilities; potential asset sales; expected impacts of the contingent payment; future investment, use and development of technology and equipment and associated future outcomes; our ability to access and implement all technology necessary to efficiently and effectively operate our assets and achieve expected future results; planned capital expenditures; and projected growth and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.
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, available at cenovus.com; bottom of the cycle commodity prices of about US$45/bbl WTI and C$44/bbl WCS in a normalized demand market; the satisfaction of the conditions to closing of the Husky Transaction in a timely manner and completion of the arrangement on the expected terms; our forecast production volumes are subject to potential further ramp down of production based on business and market conditions; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; underlying pricing fundamentals will once again support the continuation of the crude-by-rail program; suspension of the crude-by-rail program will lower transportation costs; increase to our share price and market capitalization over the long term; opportunities to repurchase shares for cancellation at prices acceptable to us; cash flows, cash balances on hand and access to credit and demand facilities being sufficient to fund capital investments; foreign exchange rate, including with respect to our US$ debt and refining capital and operating expenses; our ability to reduce our 2020 oil sands production, including without negative impacts to our assets; realization of expected capacity to store within our oil sands reservoirs barrels not yet produced, including that we will be able to time production and sales of our inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and crude oil differentials have narrowed; the Government of Alberta’s mandatory production curtailment will continue to narrow the differential between WTI and WCS crude oil
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
39 |
|
|
|
prices thereby positively impacting cash flows for Cenovus; the WTI-WCS differential in Alberta remains largely tied to the extent to which voluntary economically driven supply cuts are made, the potential start-up of the Enbridge Inc.’s Line 3 Replacement Program, the completion of Trans Mountain Expansion and Keystone XL projects, and the level of crude-by-rail activity; the ability of our refining capacity, dynamic storage, existing pipeline commitments and financial hedge transactions to partially mitigate a portion of our WCS crude oil volumes against wider differentials; production declines from both associated gas and dry gas, along with rebounding U.S. demand and liquified natural gas exports should tighten North American gas fundamentals further in 2021 and result in stronger prices than 2020 on an annual 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; future use and development of technology and associated expected future results; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to access sufficient capital to pursue our development plans; our ability to complete asset sales, including with desired transaction metrics and within the timelines we expect; forecast inflation and other assumptions inherent in our current guidance set out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the contingent payment to ConocoPhillips; our ability to access and implement all technology and equipment necessary to achieve expected future results and that such results are realized; our ability to implement capital projects or stages thereof in a successful and timely manner; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.
2020 guidance, as updated April 1, 2020, assumes: Brent prices of US$39.00/bbl, WTI prices of US$34.00/bbl; WCS of US$18.50/bbl; Differential WTI-WCS of US$15.50/bbl; AECO natural gas prices of $2.00/Mcf; Chicago 3-2-1 crack spread of US$8.30/bbl; and an exchange rate of $0.70 US$/C$.
The risk factors and uncertainties that could cause our actual results to differ materially, include, but are not limited to: the ability of Cenovus and Husky to receive, in a timely manner, the necessary regulatory, court, securityholder, stock exchange and other third-party approvals; the ability of Cenovus and Husky to satisfy, in a timely manner, the other conditions to the closing of the Husky Transaction; interloper risk; the ability to complete the transaction on the terms contemplated by the arrangement agreement between Cenovus and Husky, and other agreements, including the support agreements or at all; 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; the duration of the market downturn; a resurgence in cases of COVID-19, which has occurred in certain locations and the possibility of which in other locations remains high and creates ongoing uncertainty that could result in restrictions to contain the virus being re-imposed or imposed on a more strict basis, including restrictions on movement and businesses; the extent to which COVID-19 impacts the global economy and harms commodity prices; the extent to which COVID-19 and fluctuations in commodity prices associated with COVID-19 impacts our business, results of operations and financial condition, all of which will depend on future developments that are highly uncertain and difficult to predict, including, but not limited to the duration and spread of the pandemic, its severity, the actions taken to contain COVID-19 or treat its impact and how quickly economic activity normalizes; the success of our new COVID-19 workplace policies and the return of our people to our workplaces; our continued liquidity is sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential in Alberta does not remain largely tied to the extent to which voluntary economically driven supply cuts are made, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the Trans Mountain Expansion and Keystone XL projects, and the level of crude-by-rail activity; our ability to achieve lower transportation costs as a result of temporarily suspending the crude-by-rail program; our ability to realize the expected impacts of our capacity to store within our oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; failure of the Government of Alberta’s mandatory production curtailment 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, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; 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; changes to our dividend plans; our ability to utilize tax losses in the future; 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
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
40 |
|
|
|
goodwill from time to time; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, pandemics, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, including labour, materials, natural gas and other energy sources used in oil sands processes and increased insurance deductibles or premiums; 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, maintaining or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining 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 or storage capacity; availability of, and our ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost efficient manner; changes in labour relationships; 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; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political and economic conditions in the countries in which we operate or supply; the occurrence of unexpected events such as pandemics, war, terrorist threats 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 our material risk factors, see “Risk Management and Risk Factors” in this MD&A.
The following abbreviations have been used in this document:
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
41 |
|
|
|
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our interim Consolidated Financial Statements.
Total Production
Upstream Financial Results
|
Per Interim Consolidated Financial Statements |
|
|
Adjustments |
|
|
Basis of Netback Calculation |
|
|||||||||||||||||||||||
Three Months Ended September 30, 2020 ($ millions) |
Oil Sands (1) |
|
|
Conventional (1) (2) |
|
|
Total Upstream |
|
|
Condensate |
|
|
Inventory |
|
|
Internal Usage (3) |
|
|
Other |
|
|
Total Upstream |
|
||||||||
Gross Sales |
|
2,195 |
|
|
|
156 |
|
|
|
2,351 |
|
|
|
(747 |
) |
|
|
- |
|
|
|
(70 |
) |
|
|
(12 |
) |
|
|
1,522 |
|
Royalties |
|
129 |
|
|
|
24 |
|
|
|
153 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
153 |
|
Transportation and Blending |
|
1,015 |
|
|
|
21 |
|
|
|
1,036 |
|
|
|
(747 |
) |
|
|
6 |
|
|
|
- |
|
|
|
- |
|
|
|
295 |
|
Operating |
|
276 |
|
|
|
81 |
|
|
|
357 |
|
|
|
- |
|
|
|
- |
|
|
|
(70 |
) |
|
|
(7 |
) |
|
|
280 |
|
Inventory Write-Down (Reversal) |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Netback |
|
775 |
|
|
|
30 |
|
|
|
805 |
|
|
|
- |
|
|
|
(6 |
) |
|
|
- |
|
|
|
(5 |
) |
|
|
794 |
|
(Gain) Loss on Risk Management |
|
137 |
|
|
|
- |
|
|
|
137 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
137 |
|
Operating Margin |
|
638 |
|
|
|
30 |
|
|
|
668 |
|
|
|
- |
|
|
|
(6 |
) |
|
|
- |
|
|
|
(5 |
) |
|
|
657 |
|
|
Per Interim Consolidated Financial Statements |
|
|
Adjustments |
|
|
Basis of Netback Calculation |
|
|||||||||||||||||||||||
Three Months Ended September 30, 2019 ($ millions) |
Oil Sands (1) |
|
|
Conventional (1) (2) |
|
|
Total Upstream |
|
|
Condensate |
|
|
Inventory |
|
|
Internal Usage (3) |
|
|
Other |
|
|
Total Upstream |
|
||||||||
Gross Sales |
|
2,722 |
|
|
|
131 |
|
|
|
2,853 |
|
|
|
(924 |
) |
|
|
- |
|
|
|
(27 |
) |
|
|
(14 |
) |
|
|
1,888 |
|
Royalties |
|
336 |
|
|
|
(4 |
) |
|
|
332 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
332 |
|
Transportation and Blending |
|
1,249 |
|
|
|
20 |
|
|
|
1,269 |
|
|
|
(924 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
345 |
|
Operating |
|
227 |
|
|
|
77 |
|
|
|
304 |
|
|
|
- |
|
|
|
- |
|
|
|
(27 |
) |
|
|
(8 |
) |
|
|
269 |
|
Netback |
|
910 |
|
|
|
37 |
|
|
|
947 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(6 |
) |
|
|
941 |
|
(Gain) Loss on Risk Management |
|
(7 |
) |
|
|
- |
|
|
|
(7 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(7 |
) |
Operating Margin |
|
917 |
|
|
|
37 |
|
|
|
954 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(6 |
) |
|
|
948 |
|
|
Per Interim Consolidated Financial Statements |
|
|
Adjustments |
|
|
Basis of Netback Calculation |
|
|||||||||||||||||||||||
Nine Months Ended September 30, 2020 ($ millions) |
Oil Sands (1) |
|
|
Conventional (1) (2) |
|
|
Total Upstream |
|
|
Condensate |
|
|
Inventory |
|
|
Internal Usage (3) |
|
|
Other |
|
|
Total Upstream |
|
||||||||
Gross Sales |
|
5,287 |
|
|
|
451 |
|
|
|
5,738 |
|
|
|
(2,599 |
) |
|
|
- |
|
|
|
(203 |
) |
|
|
(41 |
) |
|
|
2,895 |
|
Royalties |
|
193 |
|
|
|
28 |
|
|
|
221 |
|
|
|
- |
|
|
|
6 |
|
|
|
- |
|
|
|
- |
|
|
|
227 |
|
Transportation and Blending |
|
3,268 |
|
|
|
63 |
|
|
|
3,331 |
|
|
|
(2,599 |
) |
|
|
285 |
|
|
|
- |
|
|
|
- |
|
|
|
1,017 |
|
Operating |
|
785 |
|
|
|
246 |
|
|
|
1,031 |
|
|
|
- |
|
|
|
25 |
|
|
|
(203 |
) |
|
|
(23 |
) |
|
|
830 |
|
Inventory Write-Down (Reversal) |
|
316 |
|
|
|
- |
|
|
|
316 |
|
|
|
|
|
|
|
(316 |
) |
|
|
|
|
|
|
|
|
|
|
- |
|
Netback |
|
725 |
|
|
|
114 |
|
|
|
839 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(18 |
) |
|
|
821 |
|
(Gain) Loss on Risk Management |
|
228 |
|
|
|
- |
|
|
|
228 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
228 |
|
Operating Margin |
|
497 |
|
|
|
114 |
|
|
|
611 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(18 |
) |
|
|
593 |
|
|
Per Interim Consolidated Financial Statements |
|
|
Adjustments |
|
|
Basis of Netback Calculation |
|
|||||||||||||||||||||||
Nine Months Ended September 30, 2019 ($ millions) |
Oil Sands (1) |
|
|
Conventional (1) (2) |
|
|
Total Upstream |
|
|
Condensate |
|
|
Inventory |
|
|
Internal Usage (3) |
|
|
Other |
|
|
Total Upstream |
|
||||||||
Gross Sales |
|
8,179 |
|
|
|
501 |
|
|
|
8,680 |
|
|
|
(2,961 |
) |
|
|
- |
|
|
|
(140 |
) |
|
|
(51 |
) |
|
|
5,528 |
|
Royalties |
|
827 |
|
|
|
20 |
|
|
|
847 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
847 |
|
Transportation and Blending |
|
3,736 |
|
|
|
62 |
|
|
|
3,798 |
|
|
|
(2,961 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
837 |
|
Operating |
|
771 |
|
|
|
257 |
|
|
|
1,028 |
|
|
|
- |
|
|
|
- |
|
|
|
(140 |
) |
|
|
(27 |
) |
|
|
861 |
|
Netback |
|
2,845 |
|
|
|
161 |
|
|
|
3,006 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(24 |
) |
|
|
2,982 |
|
(Gain) Loss on Risk Management |
|
38 |
|
|
|
- |
|
|
|
38 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
38 |
|
Operating Margin |
|
2,807 |
|
|
|
161 |
|
|
|
2,968 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(24 |
) |
|
|
2,944 |
|
(1) |
Found in Note 1 of the Interim Consolidated Financial Statements. |
(2) |
This segment was previously referred to as the Deep Basin segment. |
(3) |
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
42 |
|
|
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements (1) |
|
|||||||||||||||||||||||
Three Months Ended September 30, 2020 ($ millions) |
Foster Creek |
|
|
Christina Lake |
|
|
Total Crude Oil |
|
|
Natural Gas |
|
|
Condensate |
|
|
Inventory |
|
|
Other |
|
|
Total Oil Sands |
|
||||||||
Gross Sales |
|
605 |
|
|
|
842 |
|
|
|
1,447 |
|
|
|
- |
|
|
|
747 |
|
|
|
- |
|
|
|
1 |
|
|
|
2,195 |
|
Royalties |
|
36 |
|
|
|
93 |
|
|
|
129 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
129 |
|
Transportation and Blending |
|
125 |
|
|
|
149 |
|
|
|
274 |
|
|
|
- |
|
|
|
747 |
|
|
|
(6 |
) |
|
|
- |
|
|
|
1,015 |
|
Operating |
|
131 |
|
|
|
143 |
|
|
|
274 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
276 |
|
Inventory Write-Down (Reversal) |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Netback |
|
313 |
|
|
|
457 |
|
|
|
770 |
|
|
|
- |
|
|
|
- |
|
|
|
6 |
|
|
|
(1 |
) |
|
|
775 |
|
(Gain) Loss on Risk Management |
|
54 |
|
|
|
83 |
|
|
|
137 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
137 |
|
Operating Margin |
|
259 |
|
|
|
374 |
|
|
|
633 |
|
|
|
- |
|
|
|
- |
|
|
|
6 |
|
|
|
(1 |
) |
|
|
638 |
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements (1) |
|
|||||||||||||||||||||||
Three Months Ended September 30, 2019 ($ millions) |
Foster Creek |
|
|
Christina Lake |
|
|
Total Crude Oil |
|
|
Natural Gas |
|
|
Condensate |
|
|
Inventory |
|
|
Other |
|
|
Total Oil Sands |
|
||||||||
Gross Sales |
|
879 |
|
|
|
917 |
|
|
|
1,796 |
|
|
|
- |
|
|
|
924 |
|
|
|
- |
|
|
|
2 |
|
|
|
2,722 |
|
Royalties |
|
147 |
|
|
|
189 |
|
|
|
336 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
336 |
|
Transportation and Blending |
|
196 |
|
|
|
129 |
|
|
|
325 |
|
|
|
- |
|
|
|
924 |
|
|
|
- |
|
|
|
- |
|
|
|
1,249 |
|
Operating |
|
119 |
|
|
|
106 |
|
|
|
225 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
227 |
|
Netback |
|
417 |
|
|
|
493 |
|
|
|
910 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
910 |
|
(Gain) Loss on Risk Management |
|
(3 |
) |
|
|
(4 |
) |
|
|
(7 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(7 |
) |
Operating Margin |
|
420 |
|
|
|
497 |
|
|
|
917 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
917 |
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements (1) |
|
|||||||||||||||||||||||
Nine Months Ended September 30, 2020 ($ millions) |
Foster Creek |
|
|
Christina Lake |
|
|
Total Crude Oil |
|
|
Natural Gas |
|
|
Condensate |
|
|
Inventory |
|
|
Other |
|
|
Total Oil Sands |
|
||||||||
Gross Sales |
|
1,244 |
|
|
|
1,438 |
|
|
|
2,682 |
|
|
|
- |
|
|
|
2,599 |
|
|
|
- |
|
|
|
6 |
|
|
|
5,287 |
|
Royalties |
|
67 |
|
|
|
132 |
|
|
|
199 |
|
|
|
- |
|
|
|
- |
|
|
|
(6 |
) |
|
|
- |
|
|
|
193 |
|
Transportation and Blending |
|
523 |
|
|
|
431 |
|
|
|
954 |
|
|
|
- |
|
|
|
2,599 |
|
|
|
(285 |
) |
|
|
- |
|
|
|
3,268 |
|
Operating |
|
404 |
|
|
|
399 |
|
|
|
803 |
|
|
|
- |
|
|
|
- |
|
|
|
(25 |
) |
|
|
7 |
|
|
|
785 |
|
Inventory Write-Down (Reversal) |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
316 |
|
|
|
|
|
|
|
316 |
|
Netback |
|
250 |
|
|
|
476 |
|
|
|
726 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
725 |
|
(Gain) Loss on Risk Management |
|
96 |
|
|
|
132 |
|
|
|
228 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
228 |
|
Operating Margin |
|
154 |
|
|
|
344 |
|
|
|
498 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
497 |
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements (1) |
|
|||||||||||||||||||||||
Nine Months Ended September 30, 2019 ($ millions) |
Foster Creek |
|
|
Christina Lake |
|
|
Total Crude Oil |
|
|
Natural Gas |
|
|
Condensate |
|
|
Inventory |
|
|
Other |
|
|
Total Oil Sands |
|
||||||||
Gross Sales |
|
2,564 |
|
|
|
2,645 |
|
|
|
5,209 |
|
|
|
- |
|
|
|
2,961 |
|
|
|
- |
|
|
|
9 |
|
|
|
8,179 |
|
Royalties |
|
356 |
|
|
|
471 |
|
|
|
827 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
827 |
|
Transportation and Blending |
|
467 |
|
|
|
308 |
|
|
|
775 |
|
|
|
- |
|
|
|
2,961 |
|
|
|
- |
|
|
|
- |
|
|
|
3,736 |
|
Operating |
|
394 |
|
|
|
369 |
|
|
|
763 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8 |
|
|
|
771 |
|
Netback |
|
1,347 |
|
|
|
1,497 |
|
|
|
2,844 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
2,845 |
|
(Gain) Loss on Risk Management |
|
15 |
|
|
|
23 |
|
|
|
38 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
38 |
|
Operating Margin |
|
1,332 |
|
|
|
1,474 |
|
|
|
2,806 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
2,807 |
|
(1) |
Found in Note 1 of the Interim Consolidated Financial Statements. |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
43 |
|
|
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements(2) |
|
|||
Three Months Ended September 30, 2020 ($ millions) |
Total |
|
|
Other(3) |
|
|
Total Conventional |
|
|||
Gross Sales |
|
145 |
|
|
|
11 |
|
|
|
156 |
|
Royalties |
|
24 |
|
|
|
- |
|
|
|
24 |
|
Transportation and Blending |
|
21 |
|
|
|
- |
|
|
|
21 |
|
Operating |
|
76 |
|
|
|
5 |
|
|
|
81 |
|
Netback |
|
24 |
|
|
|
6 |
|
|
|
30 |
|
(Gain) Loss on Risk Management |
|
- |
|
|
|
- |
|
|
|
- |
|
Operating Margin |
|
24 |
|
|
|
6 |
|
|
|
30 |
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements(2) |
|
|||
Three Months Ended September 30, 2019 ($ millions) |
Total |
|
|
Other(3) |
|
|
Total Conventional |
|
|||
Gross Sales |
|
119 |
|
|
|
12 |
|
|
|
131 |
|
Royalties |
|
(4 |
) |
|
|
- |
|
|
|
(4 |
) |
Transportation and Blending |
|
20 |
|
|
|
- |
|
|
|
20 |
|
Operating |
|
71 |
|
|
|
6 |
|
|
|
77 |
|
Production and Mineral Taxes |
|
1 |
|
|
|
- |
|
|
|
1 |
|
Netback |
|
31 |
|
|
|
6 |
|
|
|
37 |
|
(Gain) Loss on Risk Management |
|
- |
|
|
|
- |
|
|
|
- |
|
Operating Margin |
|
31 |
|
|
|
6 |
|
|
|
37 |
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements(2) |
|
|||
Nine Months Ended September 30, 2020 ($ millions) |
Total |
|
|
Other(3) |
|
|
Total Conventional |
|
|||
Gross Sales |
|
416 |
|
|
|
35 |
|
|
|
451 |
|
Royalties |
|
28 |
|
|
|
- |
|
|
|
28 |
|
Transportation and Blending |
|
63 |
|
|
|
- |
|
|
|
63 |
|
Operating |
|
230 |
|
|
|
16 |
|
|
|
246 |
|
Netback |
|
95 |
|
|
|
19 |
|
|
|
114 |
|
(Gain) Loss on Risk Management |
|
- |
|
|
|
- |
|
|
|
- |
|
Operating Margin |
|
95 |
|
|
|
19 |
|
|
|
114 |
|
|
Basis of Netback Calculation |
|
|
Adjustments |
|
|
Per Interim Consolidated Financial Statements(2) |
|
|||
Nine Months Ended September 30, 2019 ($ millions) |
Total |
|
|
Other(3) |
|
|
Total Conventional |
|
|||
Gross Sales |
|
459 |
|
|
|
42 |
|
|
|
501 |
|
Royalties |
|
20 |
|
|
|
- |
|
|
|
20 |
|
Transportation and Blending |
|
62 |
|
|
|
- |
|
|
|
62 |
|
Operating |
|
238 |
|
|
|
19 |
|
|
|
257 |
|
Production and Mineral Taxes |
|
1 |
|
|
|
- |
|
|
|
1 |
|
Netback |
|
138 |
|
|
|
23 |
|
|
|
161 |
|
(Gain) Loss on Risk Management |
|
- |
|
|
|
- |
|
|
|
- |
|
Operating Margin |
|
138 |
|
|
|
23 |
|
|
|
161 |
|
(1) |
This segment was previously referred to as the Deep Basin segment. |
(2) |
Found in Note 1 of the interim Consolidated Financial Statements. |
(3) |
Reflects operating margin from processing facility. |
Cenovus Energy Inc. – Q3 2020 Management’s Discussion and Analysis |
|
44 |
|
|
|
The following table provides the sales volumes used to calculate Netback.
Sales Volumes
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
(barrels per day, unless otherwise stated) |
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Oil Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
158,280 |
|
|
|
162,199 |
|
|
|
166,180 |
|
|
|
159,108 |
|
Christina Lake |
|
238,140 |
|
|
|
192,929 |
|
|
|
222,012 |
|
|
|
182,680 |
|
Total Oil Sands (barrels per day) |
|
396,420 |
|
|
|
355,128 |
|
|
|
388,192 |
|
|
|
341,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liquids |
|
25,702 |
|
|
|
26,104 |
|
|
|
27,352 |
|
|
|
26,835 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf per day) |
|
360 |
|
|
|
407 |
|
|
|
382 |
|
|
|
432 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Conventional (BOE per day) |
|
85,713 |
|
|
|
93,901 |
|
|
|
91,062 |
|
|
|
98,807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales before Internal Consumption |
|
482,133 |
|
|
|
449,029 |
|
|
|
479,254 |
|
|
|
440,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Internal Consumption (2) (MMcf per day) |
|
(321 |
) |
|
|
(304 |
) |
|
|
(333 |
) |
|
|
(314 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Sales (2) (BOE per day) |
|
428,659 |
|
|
|
398,304 |
|
|
|
423,677 |
|
|
|
388,237 |
|
(1) |
This segment was previously referred to as the Deep Basin segment. |
(2) |
Less natural gas volumes used for internal consumption by the Oil Sands segment. |
Exhibit 99.3
Cenovus Energy Inc.
Interim Consolidated Financial Statements (unaudited)
For the Periods Ended September 30, 2020
(Canadian Dollars)
CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
For the periods ended September 30, 2020
TABLE OF CONTENTS
|
|
|
|
3 |
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) |
|
4 |
|
5 |
|
|
6 |
|
|
7 |
|
|
8 |
|
|
8 |
|
|
12 |
|
|
12 |
|
|
13 |
|
|
13 |
|
|
13 |
|
|
14 |
|
|
14 |
|
|
14 |
|
|
16 |
|
|
16 |
|
|
17 |
|
|
17 |
|
|
17 |
|
|
18 |
|
|
18 |
|
|
18 |
|
|
19 |
|
|
20 |
|
|
21 |
|
|
21 |
|
|
21 |
|
|
21 |
|
|
22 |
|
|
22 |
|
|
22 |
|
|
23 |
|
|
25 |
|
|
27 |
|
|
27 |
|
|
28 |
|
|
|
|
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
2 |
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) (unaudited)
For the periods ended September 30,
($ millions, except per share amounts)
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
|
Notes |
|
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
|
3,812 |
|
|
|
5,068 |
|
|
|
10,022 |
|
|
|
16,190 |
|
Less: Royalties |
|
|
|
153 |
|
|
|
332 |
|
|
|
221 |
|
|
|
847 |
|
|
|
|
|
3,659 |
|
|
|
4,736 |
|
|
|
9,801 |
|
|
|
15,343 |
|
Expenses |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
|
1,408 |
|
|
|
1,862 |
|
|
|
3,974 |
|
|
|
6,344 |
|
Transportation and Blending |
|
|
|
1,033 |
|
|
|
1,255 |
|
|
|
3,307 |
|
|
|
3,768 |
|
Operating |
|
|
|
481 |
|
|
|
529 |
|
|
|
1,445 |
|
|
|
1,574 |
|
Inventory Write-Down (Reversal) |
12 |
|
|
- |
|
|
|
16 |
|
|
|
549 |
|
|
|
24 |
|
Production and Mineral Taxes |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
(Gain) Loss on Risk Management |
27 |
|
|
3 |
|
|
|
- |
|
|
|
233 |
|
|
|
181 |
|
Depreciation, Depletion and Amortization |
9,13,14,15 |
|
|
1,092 |
|
|
|
558 |
|
|
|
2,615 |
|
|
|
1,668 |
|
Exploration Expense |
9,13 |
|
|
25 |
|
|
|
1 |
|
|
|
32 |
|
|
|
10 |
|
General and Administrative |
5 |
|
|
50 |
|
|
|
72 |
|
|
|
124 |
|
|
|
209 |
|
Onerous Contract Provisions |
21 |
|
|
1 |
|
|
|
(1 |
) |
|
|
- |
|
|
|
(8 |
) |
Finance Costs |
6 |
|
|
145 |
|
|
|
138 |
|
|
|
391 |
|
|
|
376 |
|
Interest Income |
|
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(4 |
) |
|
|
(9 |
) |
Foreign Exchange (Gain) Loss, Net |
7 |
|
|
(159 |
) |
|
|
88 |
|
|
|
168 |
|
|
|
(265 |
) |
Re-measurement of Contingent Payment |
20 |
|
|
(31 |
) |
|
|
(17 |
) |
|
|
(97 |
) |
|
|
137 |
|
Research Costs |
|
|
|
3 |
|
|
|
6 |
|
|
|
8 |
|
|
|
16 |
|
(Gain) Loss on Divestiture of Assets |
|
|
|
(1 |
) |
|
|
3 |
|
|
|
- |
|
|
|
7 |
|
Other (Income) Loss, Net |
8 |
|
|
(17 |
) |
|
|
(11 |
) |
|
|
(60 |
) |
|
|
(4 |
) |
Earnings (Loss) Before Income Tax |
|
|
|
(372 |
) |
|
|
239 |
|
|
|
(2,884 |
) |
|
|
1,314 |
|
Income Tax Expense (Recovery) |
10 |
|
|
(178 |
) |
|
|
52 |
|
|
|
(658 |
) |
|
|
(767 |
) |
Net Earnings (Loss) |
|
|
|
(194 |
) |
|
|
187 |
|
|
|
(2,226 |
) |
|
|
2,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Per Share ($) |
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
|
|
(0.16 |
) |
|
|
0.15 |
|
|
|
(1.81 |
) |
|
|
1.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements (unaudited).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
3 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
For the periods ended September 30,
($ millions)
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
|
Notes |
|
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
(194 |
) |
|
|
187 |
|
|
|
(2,226 |
) |
|
|
2,081 |
|
Other Comprehensive Income (Loss), Net of Tax |
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Items That Will Not be Reclassified to Profit or Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits |
|
|
|
9 |
|
|
|
(5 |
) |
|
|
(3 |
) |
|
|
(7 |
) |
Change in the Fair Value of Equity Instruments at FVOCI (1) |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
3 |
|
|
Items That May be Reclassified to Profit or Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
|
(96 |
) |
|
|
53 |
|
|
|
127 |
|
|
|
(142 |
) |
Total Other Comprehensive Income (Loss), Net of Tax |
|
|
|
(87 |
) |
|
|
48 |
|
|
|
125 |
|
|
|
(146 |
) |
Comprehensive Income (Loss) |
|
|
|
(281 |
) |
|
|
235 |
|
|
|
(2,101 |
) |
|
|
1,935 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Fair value through other comprehensive income (“FVOCI”). |
See accompanying Notes to Consolidated Financial Statements (unaudited).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
4 |
CONSOLIDATED BALANCE SHEETS (unaudited)
As at
($ millions)
|
Notes |
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
|
|
404 |
|
|
|
186 |
|
Accounts Receivable and Accrued Revenues |
|
|
|
1,137 |
|
|
|
1,551 |
|
Income Tax Receivable |
|
|
|
14 |
|
|
|
10 |
|
Inventories |
|
|
|
1,109 |
|
|
|
1,532 |
|
Risk Management |
27,28 |
|
|
3 |
|
|
|
5 |
|
Total Current Assets |
|
|
|
2,667 |
|
|
|
3,284 |
|
Exploration and Evaluation Assets, Net |
1,13 |
|
|
776 |
|
|
|
787 |
|
Property, Plant and Equipment, Net |
1,14 |
|
|
25,722 |
|
|
|
27,834 |
|
Right-of-Use Assets, Net |
1,15 |
|
|
1,202 |
|
|
|
1,325 |
|
Other Assets |
16 |
|
|
207 |
|
|
|
211 |
|
Deferred Income Taxes |
|
|
|
11 |
|
|
|
- |
|
Goodwill |
1 |
|
|
2,272 |
|
|
|
2,272 |
|
Total Assets |
|
|
|
32,857 |
|
|
|
35,713 |
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Liabilities |
|
|
|
1,549 |
|
|
|
2,210 |
|
Short-Term Borrowings |
17 |
|
|
137 |
|
|
|
- |
|
Lease Liabilities |
19 |
|
|
196 |
|
|
|
196 |
|
Contingent Payment |
20 |
|
|
20 |
|
|
|
79 |
|
Onerous Contract Provisions |
21 |
|
|
18 |
|
|
|
17 |
|
Income Tax Payable |
|
|
|
10 |
|
|
|
17 |
|
Risk Management |
27,28 |
|
|
6 |
|
|
|
2 |
|
Total Current Liabilities |
|
|
|
1,936 |
|
|
|
2,521 |
|
Long-Term Debt |
18 |
|
|
7,797 |
|
|
|
6,699 |
|
Lease Liabilities |
19 |
|
|
1,637 |
|
|
|
1,720 |
|
Contingent Payment |
20 |
|
|
26 |
|
|
|
64 |
|
Onerous Contract Provisions |
21 |
|
|
33 |
|
|
|
46 |
|
Decommissioning Liabilities |
22 |
|
|
877 |
|
|
|
1,235 |
|
Other Liabilities |
23 |
|
|
129 |
|
|
|
195 |
|
Deferred Income Taxes |
|
|
|
3,390 |
|
|
|
4,032 |
|
Total Liabilities |
|
|
|
15,825 |
|
|
|
16,512 |
|
Shareholders’ Equity |
|
|
|
17,032 |
|
|
|
19,201 |
|
Total Liabilities and Shareholders’ Equity |
|
|
|
32,857 |
|
|
|
35,713 |
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies |
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements (unaudited).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
5 |
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)
($ millions)
|
Share Capital |
|
|
Paid in Surplus |
|
|
Retained Earnings |
|
|
AOCI (1) |
|
|
Total |
|
|||||
|
(Note 24) |
|
|
|
|
|
|
|
|
|
|
(Note 25) |
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2018 |
|
11,040 |
|
|
|
4,367 |
|
|
|
1,023 |
|
|
|
1,038 |
|
|
|
17,468 |
|
Net Earnings (Loss) |
|
- |
|
|
|
- |
|
|
|
2,081 |
|
|
|
- |
|
|
|
2,081 |
|
Other Comprehensive Income (Loss) |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(146 |
) |
|
|
(146 |
) |
Total Comprehensive Income (Loss) |
|
- |
|
|
|
- |
|
|
|
2,081 |
|
|
|
(146 |
) |
|
|
1,935 |
|
Stock-Based Compensation Expense |
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
Dividends on Common Shares |
|
- |
|
|
|
- |
|
|
|
(183 |
) |
|
|
- |
|
|
|
(183 |
) |
As at September 30, 2019 |
|
11,040 |
|
|
|
4,374 |
|
|
|
2,921 |
|
|
|
892 |
|
|
|
19,227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2019 |
|
11,040 |
|
|
|
4,377 |
|
|
|
2,957 |
|
|
|
827 |
|
|
|
19,201 |
|
Net Earnings (Loss) |
|
- |
|
|
|
- |
|
|
|
(2,226 |
) |
|
|
- |
|
|
|
(2,226 |
) |
Other Comprehensive Income (Loss) |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
125 |
|
|
|
125 |
|
Total Comprehensive Income (Loss) |
|
- |
|
|
|
- |
|
|
|
(2,226 |
) |
|
|
125 |
|
|
|
(2,101 |
) |
Stock-Based Compensation Expense |
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
|
Dividends on Common Shares |
|
- |
|
|
|
- |
|
|
|
(77 |
) |
|
|
- |
|
|
|
(77 |
) |
As at September 30, 2020 |
|
11,040 |
|
|
|
4,386 |
|
|
|
654 |
|
|
|
952 |
|
|
|
17,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Accumulated other comprehensive income (loss) (“AOCI”). |
See accompanying Notes to Consolidated Financial Statements (unaudited).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
6 |
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the periods ended September 30,
($ millions)
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
|
Notes |
|
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
(194 |
) |
|
|
187 |
|
|
|
(2,226 |
) |
|
|
2,081 |
|
Depreciation, Depletion and Amortization |
9,13,14,15 |
|
|
1,092 |
|
|
|
558 |
|
|
|
2,615 |
|
|
|
1,668 |
|
Exploration Expense |
9,13 |
|
|
25 |
|
|
|
1 |
|
|
|
32 |
|
|
|
10 |
|
Inventory Write-Down (Reversal) |
|
|
|
- |
|
|
|
16 |
|
|
|
549 |
|
|
|
24 |
|
Deferred Income Tax Expense (Recovery) |
10 |
|
|
(177 |
) |
|
|
46 |
|
|
|
(656 |
) |
|
|
(790 |
) |
Unrealized (Gain) Loss on Risk Management |
27 |
|
|
(135 |
) |
|
|
9 |
|
|
|
7 |
|
|
|
157 |
|
Unrealized Foreign Exchange (Gain) Loss |
7 |
|
|
(140 |
) |
|
|
88 |
|
|
|
229 |
|
|
|
(560 |
) |
Re-measurement of Contingent Payment |
20 |
|
|
(31 |
) |
|
|
(17 |
) |
|
|
(97 |
) |
|
|
137 |
|
(Gain) Loss on Divestiture of Assets |
|
|
|
(1 |
) |
|
|
3 |
|
|
|
- |
|
|
|
7 |
|
Unwinding of Discount on Decommissioning Liabilities |
22 |
|
|
14 |
|
|
|
15 |
|
|
|
43 |
|
|
|
43 |
|
Onerous Contract Provisions, Net of Cash Paid |
21 |
|
|
(4 |
) |
|
|
(3 |
) |
|
|
(12 |
) |
|
|
(14 |
) |
Realized Inventory Write-Down |
|
|
|
(14 |
) |
|
|
(4 |
) |
|
|
(568 |
) |
|
|
(55 |
) |
Realized Foreign Exchange (Gain) Loss on Non-Operating Items |
|
|
|
(30 |
) |
|
|
(12 |
) |
|
|
(33 |
) |
|
|
279 |
|
Other |
|
|
|
9 |
|
|
|
41 |
|
|
|
(77 |
) |
|
|
28 |
|
Net Change in Other Assets and Liabilities |
|
|
|
(10 |
) |
|
|
(21 |
) |
|
|
(58 |
) |
|
|
(55 |
) |
Net Change in Non-Cash Working Capital |
|
|
|
328 |
|
|
|
(73 |
) |
|
|
275 |
|
|
|
(415 |
) |
Cash From (Used in) Operating Activities |
|
|
|
732 |
|
|
|
834 |
|
|
|
23 |
|
|
|
2,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures – Exploration and Evaluation Assets |
13 |
|
|
(1 |
) |
|
|
(20 |
) |
|
|
(42 |
) |
|
|
(40 |
) |
Capital Expenditures – Property, Plant and Equipment |
14 |
|
|
(151 |
) |
|
|
(272 |
) |
|
|
(567 |
) |
|
|
(823 |
) |
Proceeds From Divestitures |
|
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
|
|
(1 |
) |
Net Change in Investments and Other |
|
|
|
- |
|
|
|
(16 |
) |
|
|
(4 |
) |
|
|
(25 |
) |
Net Change in Non-Cash Working Capital |
|
|
|
15 |
|
|
|
(35 |
) |
|
|
(52 |
) |
|
|
(77 |
) |
Cash From (Used in) Investing Activities |
|
|
|
(136 |
) |
|
|
(343 |
) |
|
|
(663 |
) |
|
|
(966 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided (Used) Before Financing Activities |
|
|
|
596 |
|
|
|
491 |
|
|
|
(640 |
) |
|
|
1,579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities |
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance (Repayment) of Short-Term Borrowings |
|
|
|
(159 |
) |
|
|
- |
|
|
|
133 |
|
|
|
- |
|
Issuance of Long-Term Debt |
|
|
|
1,326 |
|
|
|
- |
|
|
|
1,326 |
|
|
|
- |
|
(Repayment) of Long-Term Debt |
|
|
|
- |
|
|
|
- |
|
|
|
(112 |
) |
|
|
(1,601 |
) |
Net Issuance (Repayment) of Revolving Long-Term Debt |
|
|
|
(1,444 |
) |
|
|
(1 |
) |
|
|
(220 |
) |
|
|
4 |
|
Principal Repayment of Leases |
19 |
|
|
(45 |
) |
|
|
(39 |
) |
|
|
(149 |
) |
|
|
(108 |
) |
Dividends Paid on Common Shares |
11 |
|
|
- |
|
|
|
(60 |
) |
|
|
(77 |
) |
|
|
(183 |
) |
Cash From (Used in) Financing Activities |
|
|
|
(322 |
) |
|
|
(100 |
) |
|
|
901 |
|
|
|
(1,888 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
|
(22 |
) |
|
|
(18 |
) |
|
|
(43 |
) |
|
|
(35 |
) |
|
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
252 |
|
|
|
373 |
|
|
|
218 |
|
|
|
(344 |
) |
Cash and Cash Equivalents, Beginning of Period |
|
|
|
152 |
|
|
|
64 |
|
|
|
186 |
|
|
|
781 |
|
Cash and Cash Equivalents, End of Period |
|
|
|
404 |
|
|
|
437 |
|
|
|
404 |
|
|
|
437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements (unaudited).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
7 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with marketing activities and refining operations in the United States (“U.S.”).
Cenovus is incorporated under the “Canada Business Corporations Act” and its shares are listed on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 4100, 225 6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these interim Consolidated Financial Statements is found in Note 2.
Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating margin. The Company’s reportable segments are:
|
• |
Oil Sands, which includes the development and production of bitumen in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. |
|
• |
Conventional, which includes assets rich in NGLs and natural gas within the Elmworth‑Wapiti, Kaybob-Edson, and Clearwater operating areas in Alberta and British Columbia and the exploration for heavy oil in the Marten Hills area. The assets include interests in numerous natural gas processing facilities. |
|
• |
Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S. |
|
• |
Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides. |
The following tabular financial information presents the segmented information first by segment, then by product and geographic location.
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
8 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
A) Results of Operations – Segment and Operational Information
|
|
Oil Sands |
|
|
Conventional |
|
|
Refining and Marketing |
|
|||||||||||||||
For the three months ended September 30, |
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
2,195 |
|
|
|
2,722 |
|
|
|
156 |
|
|
|
131 |
|
|
|
1,569 |
|
|
|
2,420 |
|
Less: Royalties |
|
|
129 |
|
|
|
336 |
|
|
|
24 |
|
|
|
(4 |
) |
|
|
- |
|
|
|
- |
|
|
|
|
2,066 |
|
|
|
2,386 |
|
|
|
132 |
|
|
|
135 |
|
|
|
1,569 |
|
|
|
2,420 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,444 |
|
|
|
2,026 |
|
Transportation and Blending |
|
|
1,015 |
|
|
|
1,249 |
|
|
|
21 |
|
|
|
20 |
|
|
|
- |
|
|
|
- |
|
Operating |
|
|
276 |
|
|
|
227 |
|
|
|
81 |
|
|
|
77 |
|
|
|
197 |
|
|
|
255 |
|
Inventory Write-Down (Reversal) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
16 |
|
Production and Mineral Taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
(Gain) Loss on Risk Management |
|
|
137 |
|
|
|
(7 |
) |
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
(3 |
) |
Operating Margin |
|
|
638 |
|
|
|
917 |
|
|
|
30 |
|
|
|
37 |
|
|
|
(74 |
) |
|
|
126 |
|
Depreciation, Depletion and Amortization |
|
|
469 |
|
|
|
391 |
|
|
|
75 |
|
|
|
78 |
|
|
|
521 |
|
|
|
65 |
|
Exploration Expense |
|
|
- |
|
|
|
1 |
|
|
|
25 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Segment Income (Loss) |
|
|
169 |
|
|
|
525 |
|
|
|
(70 |
) |
|
|
(41 |
) |
|
|
(595 |
) |
|
|
61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Eliminations |
|
|
Consolidated |
|
||||||||||
For the three months ended September 30, |
|
|
|
|
|
|
|
|
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
|
|
|
|
|
|
|
|
(108 |
) |
|
|
(205 |
) |
|
|
3,812 |
|
|
|
5,068 |
|
Less: Royalties |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
153 |
|
|
|
332 |
|
|
|
|
|
|
|
|
|
|
|
|
(108 |
) |
|
|
(205 |
) |
|
|
3,659 |
|
|
|
4,736 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
|
|
|
|
|
|
|
|
(36 |
) |
|
|
(164 |
) |
|
|
1,408 |
|
|
|
1,862 |
|
Transportation and Blending |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
|
(14 |
) |
|
|
1,033 |
|
|
|
1,255 |
|
Operating |
|
|
|
|
|
|
|
|
|
|
(73 |
) |
|
|
(30 |
) |
|
|
481 |
|
|
|
529 |
|
Inventory Write-Down (Reversal) |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
16 |
|
Production and Mineral Taxes |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
(Gain) Loss on Risk Management |
|
|
|
|
|
|
|
|
|
|
(136 |
) |
|
|
10 |
|
|
|
3 |
|
|
|
- |
|
Depreciation, Depletion and Amortization |
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
24 |
|
|
|
1,092 |
|
|
|
558 |
|
Exploration Expense |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
25 |
|
|
|
1 |
|
Segment Income (Loss) |
|
|
|
|
|
|
|
|
|
|
113 |
|
|
|
(31 |
) |
|
|
(383 |
) |
|
|
514 |
|
General and Administrative |
|
|
|
|
|
|
|
|
|
|
50 |
|
|
|
72 |
|
|
|
50 |
|
|
|
72 |
|
Onerous Contract Provisions |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
(1 |
) |
|
|
1 |
|
|
|
(1 |
) |
Finance Costs |
|
|
|
|
|
|
|
|
|
|
145 |
|
|
|
138 |
|
|
|
145 |
|
|
|
138 |
|
Interest Income |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(2 |
) |
|
|
(3 |
) |
Foreign Exchange (Gain) Loss, Net |
|
|
|
|
|
|
|
|
|
|
(159 |
) |
|
|
88 |
|
|
|
(159 |
) |
|
|
88 |
|
Re-measurement of Contingent Payment |
|
|
|
|
|
|
|
|
|
|
(31 |
) |
|
|
(17 |
) |
|
|
(31 |
) |
|
|
(17 |
) |
Research Costs |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
6 |
|
|
|
3 |
|
|
|
6 |
|
(Gain) Loss on Divestiture of Assets |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
3 |
|
|
|
(1 |
) |
|
|
3 |
|
Other (Income) Loss, Net |
|
|
|
|
|
|
|
|
|
|
(17 |
) |
|
|
(11 |
) |
|
|
(17 |
) |
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
|
(11 |
) |
|
|
275 |
|
|
|
(11 |
) |
|
|
275 |
|
Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
(372 |
) |
|
|
239 |
|
|||||||
Income Tax Expense (Recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(178 |
) |
|
|
52 |
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(194 |
) |
|
|
187 |
|
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
9 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
|
Oil Sands |
|
|
Conventional |
|
|
Refining and Marketing |
|
||||||||||||||||
For the nine months ended September 30, |
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
5,287 |
|
|
|
8,179 |
|
|
|
451 |
|
|
|
501 |
|
|
|
4,706 |
|
|
|
7,958 |
|
Less: Royalties |
|
|
193 |
|
|
|
827 |
|
|
|
28 |
|
|
|
20 |
|
|
|
- |
|
|
|
- |
|
|
|
|
5,094 |
|
|
|
7,352 |
|
|
|
423 |
|
|
|
481 |
|
|
|
4,706 |
|
|
|
7,958 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,170 |
|
|
|
6,622 |
|
Transportation and Blending |
|
|
3,268 |
|
|
|
3,736 |
|
|
|
63 |
|
|
|
62 |
|
|
|
- |
|
|
|
- |
|
Operating |
|
|
785 |
|
|
|
771 |
|
|
|
246 |
|
|
|
257 |
|
|
|
624 |
|
|
|
698 |
|
Inventory Write-Down (Reversal) |
|
|
316 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
233 |
|
|
|
24 |
|
Production and Mineral Taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
(Gain) Loss on Risk Management |
|
|
228 |
|
|
|
38 |
|
|
|
- |
|
|
|
- |
|
|
|
(6 |
) |
|
|
(14 |
) |
Operating Margin |
|
|
497 |
|
|
|
2,807 |
|
|
|
114 |
|
|
|
161 |
|
|
|
(315 |
) |
|
|
628 |
|
Depreciation, Depletion and Amortization |
|
|
1,275 |
|
|
|
1,127 |
|
|
|
563 |
|
|
|
247 |
|
|
|
673 |
|
|
|
213 |
|
Exploration Expense |
|
|
7 |
|
|
|
10 |
|
|
|
25 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Segment Income (Loss) |
|
|
(785 |
) |
|
|
1,670 |
|
|
|
(474 |
) |
|
|
(86 |
) |
|
|
(988 |
) |
|
|
415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Eliminations |
|
|
Consolidated |
|
||||||||||
For the nine months ended September 30, |
|
|
|
|
|
|
|
|
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
|
|
|
|
|
|
|
|
(422 |
) |
|
|
(448 |
) |
|
|
10,022 |
|
|
|
16,190 |
|
Less: Royalties |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
221 |
|
|
|
847 |
|
|
|
|
|
|
|
|
|
|
|
|
(422 |
) |
|
|
(448 |
) |
|
|
9,801 |
|
|
|
15,343 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
|
|
|
|
|
|
|
|
(196 |
) |
|
|
(278 |
) |
|
|
3,974 |
|
|
|
6,344 |
|
Transportation and Blending |
|
|
|
|
|
|
|
|
|
|
(24 |
) |
|
|
(30 |
) |
|
|
3,307 |
|
|
|
3,768 |
|
Operating |
|
|
|
|
|
|
|
|
|
|
(210 |
) |
|
|
(152 |
) |
|
|
1,445 |
|
|
|
1,574 |
|
Inventory Write-Down (Reversal) |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
549 |
|
|
|
24 |
|
Production and Mineral Taxes |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
(Gain) Loss on Risk Management |
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
157 |
|
|
|
233 |
|
|
|
181 |
|
Depreciation, Depletion and Amortization |
|
|
|
|
|
|
|
|
|
|
104 |
|
|
|
81 |
|
|
|
2,615 |
|
|
|
1,668 |
|
Exploration Expense |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
32 |
|
|
|
10 |
|
Segment Income (Loss) |
|
|
|
|
|
|
|
|
|
|
(107 |
) |
|
|
(226 |
) |
|
|
(2,354 |
) |
|
|
1,773 |
|
General and Administrative |
|
|
|
|
|
|
|
|
|
|
124 |
|
|
|
209 |
|
|
|
124 |
|
|
|
209 |
|
Onerous Contract Provisions |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
(8 |
) |
|
|
- |
|
|
|
(8 |
) |
Finance Costs |
|
|
|
|
|
|
|
|
|
|
391 |
|
|
|
376 |
|
|
|
391 |
|
|
|
376 |
|
Interest Income |
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
(9 |
) |
|
|
(4 |
) |
|
|
(9 |
) |
Foreign Exchange (Gain) Loss, Net |
|
|
|
|
|
|
|
|
|
|
168 |
|
|
|
(265 |
) |
|
|
168 |
|
|
|
(265 |
) |
Re-measurement of Contingent Payment |
|
|
|
|
|
|
|
|
|
|
(97 |
) |
|
|
137 |
|
|
|
(97 |
) |
|
|
137 |
|
Research Costs |
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
16 |
|
|
|
8 |
|
|
|
16 |
|
(Gain) Loss on Divestiture of Assets |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
7 |
|
Other (Income) Loss, Net |
|
|
|
|
|
|
|
|
|
|
(60 |
) |
|
|
(4 |
) |
|
|
(60 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
530 |
|
|
|
459 |
|
|
|
530 |
|
|
|
459 |
|
Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
(2,884 |
) |
|
|
1,314 |
|
|||||||
Income Tax Expense (Recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(658 |
) |
|
|
(767 |
) |
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,226 |
) |
|
|
2,081 |
|
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
10 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
2,093 |
|
|
|
2,412 |
|
|
|
5,156 |
|
|
|
7,417 |
|
Natural Gas |
|
69 |
|
|
|
47 |
|
|
|
217 |
|
|
|
214 |
|
NGLs |
|
24 |
|
|
|
48 |
|
|
|
103 |
|
|
|
151 |
|
Other |
|
12 |
|
|
|
14 |
|
|
|
41 |
|
|
|
51 |
|
Refined Products |
|
1,238 |
|
|
|
2,087 |
|
|
|
3,634 |
|
|
|
6,202 |
|
Market Optimization |
|
331 |
|
|
|
333 |
|
|
|
1,072 |
|
|
|
1,756 |
|
Corporate and Eliminations |
|
(108 |
) |
|
|
(205 |
) |
|
|
(422 |
) |
|
|
(448 |
) |
Consolidated |
|
3,659 |
|
|
|
4,736 |
|
|
|
9,801 |
|
|
|
15,343 |
|
C) Geographical Information
|
Revenues |
|
|||||||||||||
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Canada |
|
2,418 |
|
|
|
2,623 |
|
|
|
6,089 |
|
|
|
9,077 |
|
United States |
|
1,241 |
|
|
|
2,113 |
|
|
|
3,712 |
|
|
|
6,266 |
|
Consolidated |
|
3,659 |
|
|
|
4,736 |
|
|
|
9,801 |
|
|
|
15,343 |
|
|
|
|
|
|
Non-Current Assets (1) |
|
|||||
As at |
|
|
|
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Canada |
|
|
|
|
|
26,454 |
|
|
|
28,336 |
|
United States |
|
|
|
|
|
3,725 |
|
|
|
4,093 |
|
Consolidated |
|
|
|
|
|
30,179 |
|
|
|
32,429 |
|
(1) |
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, other assets and goodwill. |
D) Assets by Segment
|
E&E Assets (1) |
|
|
PP&E |
|
|
ROU Assets |
|
|||||||||||||||
As at |
September 30, 2020 |
|
|
December 31, 2019 |
|
|
September 30, 2020 |
|
|
December 31, 2019 |
|
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||||||
Oil Sands |
|
615 |
|
|
|
594 |
|
|
|
19,974 |
|
|
|
20,924 |
|
|
|
667 |
|
|
|
768 |
|
Conventional |
|
161 |
|
|
|
193 |
|
|
|
1,679 |
|
|
|
2,433 |
|
|
|
3 |
|
|
|
3 |
|
Refining and Marketing |
|
- |
|
|
|
- |
|
|
|
3,758 |
|
|
|
4,131 |
|
|
|
92 |
|
|
|
77 |
|
Corporate and Eliminations |
|
- |
|
|
|
- |
|
|
|
311 |
|
|
|
346 |
|
|
|
440 |
|
|
|
477 |
|
Consolidated |
|
776 |
|
|
|
787 |
|
|
|
25,722 |
|
|
|
27,834 |
|
|
|
1,202 |
|
|
|
1,325 |
|
|
|
|
Goodwill |
|
|
Total Assets |
|
||||||||||||
As at |
|
|
|
|
September 30, 2020 |
|
|
December 31, 2019 |
|
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||||
Oil Sands |
|
|
|
|
|
2,272 |
|
|
|
2,272 |
|
|
|
24,676 |
|
|
|
26,203 |
|
Conventional |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
1,909 |
|
|
|
2,754 |
|
Refining and Marketing |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
4,989 |
|
|
|
5,688 |
|
Corporate and Eliminations |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
1,283 |
|
|
|
1,068 |
|
Consolidated |
|
|
|
|
|
2,272 |
|
|
|
2,272 |
|
|
|
32,857 |
|
|
|
35,713 |
|
(1) |
Marten Hills was reclassified from the Oil Sands segment to the Conventional segment and the comparative period has been reclassified. |
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
11 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Capital Investment (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
65 |
|
|
|
134 |
|
|
|
337 |
|
|
|
477 |
|
Conventional |
|
12 |
|
|
|
32 |
|
|
|
39 |
|
|
|
61 |
|
Refining and Marketing |
|
65 |
|
|
|
87 |
|
|
|
172 |
|
|
|
214 |
|
Corporate and Eliminations |
|
6 |
|
|
|
41 |
|
|
|
51 |
|
|
|
107 |
|
|
|
148 |
|
|
|
294 |
|
|
|
599 |
|
|
|
859 |
|
Acquisition Capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
1 |
|
|
|
- |
|
|
|
6 |
|
|
|
2 |
|
Conventional |
|
3 |
|
|
|
- |
|
|
|
4 |
|
|
|
3 |
|
Refining and Marketing |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
Total Capital Expenditures |
|
152 |
|
|
|
294 |
|
|
|
609 |
|
|
|
868 |
|
(1) |
Includes expenditures on PP&E and E&E assets. |
(2) |
Marten Hills was reclassified from the Oil Sands segment to the Conventional segment and the comparative period has been reclassified. |
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these interim Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.
These interim Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting” (“IAS 34”), and have been prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2019, except for income taxes and the accounting policies disclosed in Note 3. Income taxes on earnings or loss in the interim periods are accrued using the income tax rate that would be applicable to the expected total annual earnings or loss.
Certain information provided for the prior year has been reclassified to conform to the presentation adopted for the period ended September 30, 2020. Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2019, which have been prepared in accordance with IFRS as issued by the IASB.
These interim Consolidated Financial Statements were approved by the Board of Directors effective October 28, 2020.
3. UPDATE TO SIGNIFICANT ACCOUNTING POLICIES
Government Grants
Government grants are recognized when there is reasonable assurance that the grant will be received and all conditions associated with the grant are met. Grants related to assets are recorded as a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the services have been performed.
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
12 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
4. RECENT DEVELOPMENTS AND IMPACT ON ESTIMATION UNCERTAINTY
In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of the coronavirus (“COVID-19”). The outbreak and subsequent measures intended to limit the pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil.
The full extent of the impact of COVID-19 on the Company’s operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by Management in the preparation of its financial results.
A full list of the key sources of estimation uncertainty can be found in the Company’s annual Consolidated Financial Statements for the year ended December 31, 2019. The outbreak and current market conditions have increased the complexity of estimates and assumptions used to prepare the interim Consolidated Financial Statements, particularly related to the following key sources of estimation uncertainty:
Recoverable Amounts
Determining the recoverable amount of a cash-generating unit (“CGU”) or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. The severe drop in commodity prices, including refined products, and the decline in market crack spreads due to reasons noted above, have increased the risk of measurement uncertainty in determining the recoverable amounts, especially estimating economic crude oil and natural gas reserves and estimating forward commodity prices.
Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of a liability and to estimate the future amount of the liability. Market volatility at September 30, 2020 increased the measurement uncertainty inherent in determining the appropriate credit-adjusted discount rate that is used in the estimation of decommissioning liabilities.
Income Tax Provisions
Income taxes on earnings or loss in the interim periods are accrued using the income tax rate that would be applicable to the expected total annual earnings or loss. There is increased measurement uncertainty related to the expected total annual earnings due to the reduced demand for crude oil, natural gas and refined products, as well as the fluctuation of commodity prices as a result of COVID-19.
Changes to these assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Salaries and Benefits |
|
35 |
|
|
|
33 |
|
|
|
105 |
|
|
|
97 |
|
Administrative and Other |
|
18 |
|
|
|
19 |
|
|
|
65 |
|
|
|
67 |
|
Stock-Based Compensation Expense (Recovery) |
|
(3 |
) |
|
|
20 |
|
|
|
(15 |
) |
|
|
45 |
|
Other Long-Term Incentive Benefits Expense (Recovery) |
|
- |
|
|
|
- |
|
|
|
(31 |
) |
|
|
- |
|
|
|
50 |
|
|
|
72 |
|
|
|
124 |
|
|
|
209 |
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Interest Expense – Short-Term Borrowings and Long-Term Debt |
|
103 |
|
|
|
97 |
|
|
|
288 |
|
|
|
317 |
|
Net (Discount) Premium on Redemption of Long-Term Debt (Note 18) |
|
- |
|
|
|
- |
|
|
|
(25 |
) |
|
|
(64 |
) |
Interest Expense – Lease Liabilities (Note 19) |
|
22 |
|
|
|
20 |
|
|
|
66 |
|
|
|
59 |
|
Unwinding of Discount on Decommissioning Liabilities (Note 22) |
|
14 |
|
|
|
15 |
|
|
|
43 |
|
|
|
43 |
|
Other |
|
6 |
|
|
|
6 |
|
|
|
19 |
|
|
|
21 |
|
|
|
145 |
|
|
|
138 |
|
|
|
391 |
|
|
|
376 |
|
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
13 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Unrealized Foreign Exchange (Gain) Loss on Translation of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Dollar Debt Issued From Canada |
|
(152 |
) |
|
|
86 |
|
|
|
164 |
|
|
|
(542 |
) |
Other |
|
12 |
|
|
|
2 |
|
|
|
65 |
|
|
|
(18 |
) |
Unrealized Foreign Exchange (Gain) Loss |
|
(140 |
) |
|
|
88 |
|
|
|
229 |
|
|
|
(560 |
) |
Realized Foreign Exchange (Gain) Loss |
|
(19 |
) |
|
|
- |
|
|
|
(61 |
) |
|
|
295 |
|
|
|
(159 |
) |
|
|
88 |
|
|
|
168 |
|
|
|
(265 |
) |
The Government of Canada passed the Canada Emergency Wage Subsidy (“CEWS”) as part of its COVID-19 Economic Response Plan. The program is effective from March 15, 2020 to the summer of 2021. For the nine months ended September 30, 2020, the Company recorded $40 million in other income from the CEWS program.
A) Cash-Generating Unit Impairments
On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount.
2020 Upstream Impairments
As at September 30, 2020, there were no indicators of impairment nor impairment reversals. For the purpose of impairment testing, goodwill is allocated to the CGU of which it relates. There was no impairment of goodwill as at September 30, 2020.
As at March 31, 2020, the Company determined that the carrying amount was greater than the recoverable amount of certain CGUs and recorded an impairment loss of $315 million as additional depreciation, depletion and amortization (“DD&A”) in the Conventional segment. Future cash flows for the CGUs declined primarily due to lower forward commodity prices. The following table summarizes the impairment losses and estimated recoverable amounts by CGU:
Cash-Generating Unit |
Impairment Amount |
|
|
|
Recoverable Amount |
|
||
Clearwater |
|
140 |
|
|
|
|
306 |
|
Kaybob-Edson |
|
175 |
|
|
|
|
414 |
|
Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on fair value less costs of disposal (“FVLCOD”). Key assumptions in the determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates at March 31, 2020. All reserves were evaluated as at December 31, 2019 by the Company’s independent qualified reserves evaluators (“IQREs”).
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at March 31, 2020 used to determine future cash flows from crude oil, NGLs and natural gas reserves were:
|
Remainder of 2020 |
|
|
2021 |
|
|
2022 |
|
|
2023 |
|
|
2024 |
|
|
Average Annual Increase Thereafter |
|
||||||
WTI (US$/barrel) (1) |
|
31.67 |
|
|
|
42.57 |
|
|
|
50.51 |
|
|
|
58.17 |
|
|
|
60.66 |
|
|
|
2.1 |
% |
WCS (C$/barrel) (2) |
|
22.56 |
|
|
|
36.32 |
|
|
|
46.10 |
|
|
|
54.85 |
|
|
|
57.96 |
|
|
|
2.1 |
% |
Edmonton C5+ (C$/barrel) |
|
34.80 |
|
|
|
51.28 |
|
|
|
63.07 |
|
|
|
72.38 |
|
|
|
75.67 |
|
|
|
2.1 |
% |
AECO (C$/Mcf) (3) |
|
1.90 |
|
|
|
2.28 |
|
|
|
2.45 |
|
|
|
2.58 |
|
|
|
2.65 |
|
|
|
2.0 |
% |
(1) |
West Texas Intermediate (“WTI”). |
(2) |
Western Canadian Select (“WCS”). |
(3) |
Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units per thousand cubic feet (“Mcf”). |
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
14 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation was estimated at approximately two percent.
Sensitivities
The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount in the impairment testing completed as at March 31, 2020 for the following CGUs:
|
|
Increase (Decrease) to Recoverable Amount |
|
|||||||||||||
|
One Percent Increase in the Discount Rate |
|
|
One Percent Decrease in the Discount Rate |
|
|
Five Percent Increase in the Forward Price Estimates |
|
|
Five Percent Decrease in the Forward Price Estimates |
|
|||||
Clearwater |
|
|
(15 |
) |
|
|
15 |
|
|
|
77 |
|
|
|
(74 |
) |
Elmworth-Wapiti |
|
|
(16 |
) |
|
|
16 |
|
|
|
67 |
|
|
|
(65 |
) |
Kaybob-Edson |
|
|
(25 |
) |
|
|
28 |
|
|
|
75 |
|
|
|
(73 |
) |
Narrows Lake |
|
|
(369 |
) |
|
|
457 |
|
|
|
240 |
|
|
|
(239 |
) |
2020 Refining Impairments
The recovery in demand for refined products from the impact of COVID-19 has lagged expectations resulting in higher than anticipated inventory levels. These factors, along with low market crack spreads and crude oil processing runs for North American refineries, were identified as potential indicators of impairment for the Wood River and Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was determined to be greater than the recoverable amount and an impairment charge of $450 million was recorded as additional DD&A in the Refining and Marketing segment. The recoverable amount of the Borger CGU has been estimated at $692 million, using a discounted cash flow method in accordance with IFRS. No impairment of the Wood River CGU was identified.
Key Assumptions
The recoverable amount (Level 3) of the Borger CGU was determined in accordance with IFRS using FVLCOD and an evaluation of comparable asset transactions. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows include forward crude oil prices, forward crack spreads and the discount rate. Forward crack spreads are based on quoted near-month contracts for WTI and spot prices for gasoline and diesel.
Crude Oil and Forward Crack Spreads
Forward prices are based on the Management’s best estimate and corroborated with third party data. As at September 30, 2020, the forward prices used to determine future cash flows were:
|
• |
WTI forward prices used for 2021 to 2022 ranged from US$36.36 per barrel to US$50.84 per barrel and 2023 to 2025 ranged from US$49.66 per barrel to US$58.74 per barrel; |
|
• |
WTI to West Texas Sour differential used for 2021 to 2022 ranged from US$0.37 per barrel to US$1.73 per barrel and 2023 to 2025 ranged from US$1.21 per barrel to US$1.81 per barrel; |
|
• |
Group 3 forward market crack spread used for 2021 to 2022 ranged from US$11.56 per barrel to US$13.23 per barrel and 2023 to 2025 ranged from US$11.79 per barrel to US$16.58 per barrel; and |
|
• |
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035. |
Discount Rates
Discounted future cash flows are determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors.
Sensitivities
The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have on the calculated recoverable amount in the impairment testing for the following CGU:
|
|
Increase (Decrease) to Recoverable Amount |
|
|||||||||||||
|
|
One Percent Increase in the Discount Rate |
|
|
One Percent Decrease in the Discount Rate |
|
|
Five Percent Increase in the Forward Price Estimates |
|
|
Five Percent Decrease in the Forward Price Estimates |
|
||||
Borger |
|
|
(71 |
) |
|
|
81 |
|
|
|
263 |
|
|
|
(264 |
) |
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
15 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
As at September 30, 2020, there were no indicators of impairment for the Company’s ROU assets. As at March 31, 2020, the temporary suspension of the Company’s crude-by-rail program was considered to be an indicator of impairment for the railcar CGU. As a result, the CGU was tested for impairment and an impairment expense of $3 million was recorded as additional DD&A.
2019 Upstream Impairments
As at September 30, 2019, forward natural gas prices declined by approximately 15 percent since the Company tested its upstream CGUs for impairment as at December 31, 2018. Therefore, the Company tested its upstream CGUs with natural gas reserves for impairment. As at September 30, 2019, there was no impairment of goodwill or the Company’s CGUs.
B) Asset Impairments and Write-downs
Exploration and Evaluation Assets
For the nine months ended September 30, 2020, $7 million and $25 million of previously capitalized E&E costs were written off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be recoverable and recorded as exploration expense.
Property, Plant and Equipment, Net
For the nine months ended September 30, 2020, $46 million of previously capitalized PP&E costs were written off as the carrying value was not considered to be recoverable. The impairment was recorded as additional DD&A in the Oil Sands segment.
The provision for income taxes is:
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
(1 |
) |
|
|
10 |
|
|
|
(3 |
) |
|
|
22 |
|
United States |
|
- |
|
|
|
(4 |
) |
|
|
1 |
|
|
|
1 |
|
Total Current Tax Expense (Recovery) |
|
(1 |
) |
|
|
6 |
|
|
|
(2 |
) |
|
|
23 |
|
Deferred Tax Expense (Recovery) |
|
(177 |
) |
|
|
46 |
|
|
|
(656 |
) |
|
|
(790 |
) |
|
|
(178 |
) |
|
|
52 |
|
|
|
(658 |
) |
|
|
(767 |
) |
For the three and nine months ended September 30, 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU and current period operating losses that will be carried forward, excluding unrealized foreign exchange gains and losses on long-term debt.
In 2019, the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to eight percent over four years. As a result, the Company recorded a deferred income tax recovery of $663 million for the nine months ended September 30, 2019. In addition, the Company recorded a deferred income tax recovery of $387 million due to an internal restructuring of the Company’s U.S. operations resulting in a step-up in the tax basis of the Company’s refining assets.
A) Net Earnings (Loss) Per Share – Basic and Diluted
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Net Earnings (Loss) ($ millions) |
|
(194 |
) |
|
|
187 |
|
|
|
(2,226 |
) |
|
|
2,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic – Weighted Average Number of Shares (millions) |
|
1,228.9 |
|
|
|
1,228.8 |
|
|
|
1,228.9 |
|
|
|
1,228.8 |
|
Dilutive Effect of Cenovus NSRs (1) (millions) |
|
- |
|
|
|
0.6 |
|
|
|
- |
|
|
|
0.5 |
|
Diluted – Weighted Average Number of Shares (millions) |
|
1,228.9 |
|
|
|
1,229.4 |
|
|
|
1,228.9 |
|
|
|
1,229.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Per Share - Basic and Diluted ($) |
|
(0.16 |
) |
|
|
0.15 |
|
|
|
(1.81 |
) |
|
|
1.69 |
|
(1) |
Net settlement rights (“NSRs”). |
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
16 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
The Company temporarily suspended its dividend in response to the low global oil price environment. Prior to the suspension, the Company paid dividends of $77 million or $0.0625 per share in the first three months of 2020 (nine months ended September 30, 2019 – $183 million or $0.15 per share). The declaration of dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.
As at March 31, 2020, the Company recorded $588 million in non-cash inventory write-downs of its crude oil blend, condensate and refined product inventory. Subsequently, $543 million of inventory that was written down at the end of March was sold and the loss was realized. For the nine months ended September 30, 2020, the Company reversed $39 million of the inventory write-downs related to March product inventories that was still on hand due to improved refined product and crude oil prices.
As at December 31, 2019, the Company recorded a $25 million write-down in refined product inventory.
13. EXPLORATION AND EVALUATION ASSETS, NET
|
Total |
|
|
As at December 31, 2019 |
|
787 |
|
Additions |
|
42 |
|
Exploration Expense (Note 9) |
|
(32 |
) |
Depletion |
|
(15 |
) |
Change in Decommissioning Liabilities |
|
(4 |
) |
Exchange Rate Movements and Other |
|
(2 |
) |
As at September 30, 2020 |
|
776 |
|
14. PROPERTY, PLANT AND EQUIPMENT, NET
(1) |
Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft. |
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
17 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
|
Real Estate |
|
|
Railcars & Barges |
|
|
Storage Assets (1) |
|
|
Refining Equipment |
|
|
Other |
|
|
Total |
|
||||||
COST |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2019 |
|
509 |
|
|
|
495 |
|
|
|
464 |
|
|
|
10 |
|
|
|
14 |
|
|
|
1,492 |
|
Additions |
|
- |
|
|
|
18 |
|
|
|
23 |
|
|
|
5 |
|
|
|
6 |
|
|
|
52 |
|
Terminations |
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
Modifications |
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
(4 |
) |
|
|
(3 |
) |
Reclassifications |
|
(13 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(13 |
) |
Re-measurement |
|
- |
|
|
|
(13 |
) |
|
|
19 |
|
|
|
- |
|
|
|
(1 |
) |
|
|
5 |
|
Exchange Rate Movements and Other |
|
(1 |
) |
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
(3 |
) |
|
|
(3 |
) |
As at September 30, 2020 |
|
495 |
|
|
|
501 |
|
|
|
506 |
|
|
|
15 |
|
|
|
12 |
|
|
|
1,529 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ACCUMULATED DEPRECIATION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2019 |
|
32 |
|
|
|
55 |
|
|
|
73 |
|
|
|
3 |
|
|
|
4 |
|
|
|
167 |
|
Depreciation |
|
21 |
|
|
|
66 |
|
|
|
71 |
|
|
|
2 |
|
|
|
3 |
|
|
|
163 |
|
Impairment Charges (Note 9) |
|
- |
|
|
|
3 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
Terminations |
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
Exchange Rate Movements and Other |
|
(1 |
) |
|
|
- |
|
|
|
(2 |
) |
|
|
- |
|
|
|
(2 |
) |
|
|
(5 |
) |
As at September 30, 2020 |
|
52 |
|
|
|
124 |
|
|
|
141 |
|
|
|
5 |
|
|
|
5 |
|
|
|
327 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CARRYING VALUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2019 |
|
477 |
|
|
|
440 |
|
|
|
391 |
|
|
|
7 |
|
|
|
10 |
|
|
|
1,325 |
|
As at September 30, 2020 |
|
443 |
|
|
|
377 |
|
|
|
365 |
|
|
|
10 |
|
|
|
7 |
|
|
|
1,202 |
|
(1) |
Storage assets include caverns and tanks. |
For the nine months ended September 30, 2020, the Company recognized $19 million of lease income (nine months ended September 30, 2019 – $13 million). Lease income is earned on tank subleases, operating leases related to the Company’s real estate ROU assets in which Cenovus is the lessor, and from the recovery of non-lease components for operating costs and unreserved parking related to the Company’s net investment in finance leases. Finance leases are included in other assets as net investment in finance leases.
As at |
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Intangible Assets |
|
91 |
|
|
|
101 |
|
Equity Investments (Note 27) |
|
53 |
|
|
|
52 |
|
Net Investment in Finance Leases |
|
52 |
|
|
|
30 |
|
Long-Term Receivables |
|
6 |
|
|
|
21 |
|
Prepaids |
|
5 |
|
|
|
7 |
|
|
|
207 |
|
|
|
211 |
|
Demand Facilities
The Company has uncommitted demand facilities of $1.6 billion in place, of which $600 million may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at September 30, 2020, no amount was drawn on these facilities (December 31, 2019 – $nil) and there were outstanding letters of credit aggregating to $457 million (December 31, 2019 – $364 million).
WRB Refining LP (“WRB”) has uncommitted demand facilities of US$300 million (the Company’s proportionate share – US$150 million) available to cover short-term working capital requirements. As at September 30, 2020, US$205 million was drawn on the facilities, of which US$103 million (C$137 million) was the Company’s proportionate share (December 31, 2019 – $nil).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
18 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
18. LONG-TERM DEBT AND CAPITAL STRUCTURE
As at |
Notes |
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Revolving Term Debt (1) |
A |
|
|
- |
|
|
|
265 |
|
U.S. Dollar Denominated Unsecured Notes |
B |
|
|
7,868 |
|
|
|
6,492 |
|
Total Debt Principal |
|
|
|
7,868 |
|
|
|
6,757 |
|
Debt Discounts and Transaction Costs |
|
|
|
(71 |
) |
|
|
(58 |
) |
Long-Term Debt |
|
|
|
7,797 |
|
|
|
6,699 |
|
(1) |
Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans. |
A) Committed Credit Facilities
Cenovus has in place a committed revolving credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche with maturity dates of November 30, 2022 and November 30, 2023, respectively. In April 2020, the Company added a committed credit facility with capacity of $1.1 billion to further support the Company’s financial resilience in the current market environment. The new facility has a term of 364 days that is renewable for one year at the Company’s request and upon approval by the lenders.
B) U.S. Dollar Denominated Unsecured Notes
On July 30, 2020, Cenovus completed a public offering in the U.S., under the Company’s U.S. base shelf prospectus, of senior unsecured notes in the aggregate principal of US$1.0 billion due in 2025. As at September 30, 2020, US$4.0 billion is available under the base shelf prospectus.
In the three months ended March 31, 2020, the Company paid US$81 million to repurchase a portion of its unsecured notes with a principal amount of US$100 million. A gain on the repurchase of $25 million was recorded in finance costs (Note 6).
The remaining principal amounts of the Company’s U.S. dollar denominated unsecured notes are:
As at September 30, 2020 |
US$ Principal Amount |
|
|
3.00% due August 15, 2022 |
|
500 |
|
3.80% due September 15, 2023 |
|
450 |
|
5.38% due July 15, 2025 |
|
1,000 |
|
4.25% due April 15, 2027 |
|
962 |
|
5.25% due June 15, 2037 |
|
583 |
|
6.75% due November 15, 2039 |
|
1,390 |
|
4.45% due September 15, 2042 |
|
155 |
|
5.20% due September 15, 2043 |
|
58 |
|
5.40% due June 15, 2047 |
|
800 |
|
|
|
5,898 |
|
As at September 30, 2020, the Company is in compliance with all of the terms of its debt agreements.
C) Capital Structure
Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. Cenovus conducts its business and makes decisions consistent with that of an investment grade company. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase the Company’s common shares for cancellation, issue new debt, or issue new shares.
Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.
Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may periodically be above the target due to factors such as persistently low commodity prices. Cenovus also manages its Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit facility agreements.
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
19 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
As at |
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Short-Term Borrowings |
|
137 |
|
|
|
- |
|
Long-Term Debt |
|
7,797 |
|
|
|
6,699 |
|
Less: Cash and Cash Equivalents |
|
(404 |
) |
|
|
(186 |
) |
Net Debt |
|
7,530 |
|
|
|
6,513 |
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
(2,113 |
) |
|
|
2,194 |
|
Add (Deduct): |
|
|
|
|
|
|
|
Finance Costs |
|
526 |
|
|
|
511 |
|
Interest Income |
|
(7 |
) |
|
|
(12 |
) |
Income Tax Expense (Recovery) |
|
(688 |
) |
|
|
(797 |
) |
Depreciation, Depletion and Amortization |
|
3,196 |
|
|
|
2,249 |
|
E&E Write-Down |
|
104 |
|
|
|
82 |
|
Unrealized (Gain) Loss on Risk Management |
|
(1 |
) |
|
|
149 |
|
Foreign Exchange (Gain) Loss, Net |
|
29 |
|
|
|
(404 |
) |
Re-measurement of Contingent Payment |
|
(70 |
) |
|
|
164 |
|
(Gain) Loss on Divestitures of Assets |
|
(9 |
) |
|
|
(2 |
) |
Other (Income) Loss, Net |
|
(67 |
) |
|
|
(11 |
) |
Adjusted EBITDA (1) |
|
900 |
|
|
|
4,123 |
|
|
|
|
|
|
|
|
|
Net Debt to Adjusted EBITDA |
8.4x |
|
|
1.6x |
|
(1) |
Calculated on a trailing twelve-month basis. |
Net Debt to Capitalization
As at |
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Net Debt |
|
7,530 |
|
|
|
6,513 |
|
Shareholders’ Equity |
|
17,032 |
|
|
|
19,201 |
|
|
|
24,562 |
|
|
|
25,714 |
|
|
|
|
|
|
|
|
|
Net Debt to Capitalization |
31% |
|
|
25% |
|
Under the terms of Cenovus’s committed credit facilities, the Company is required to maintain a debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is well below this limit.
|
Total |
|
|
As at December 31, 2019 |
|
1,916 |
|
Additions |
|
48 |
|
Interest Expense (Note 6) |
|
66 |
|
Lease Payments |
|
(215 |
) |
Terminations |
|
(1 |
) |
Modifications |
|
(3 |
) |
Re-measurement |
|
5 |
|
Exchange Rate Movements and Other |
|
17 |
|
As at September 30, 2020 |
|
1,833 |
|
Less: Current Portion |
|
196 |
|
Long-Term Portion |
|
1,637 |
|
The Company has lease liabilities for contracts related to office space, railcars, barges, storage assets, service rig, and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions.
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Variable Lease Payments |
|
4 |
|
|
|
5 |
|
|
|
11 |
|
|
|
15 |
|
Short-Term Lease Payments |
|
1 |
|
|
|
3 |
|
|
|
4 |
|
|
|
10 |
|
The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are leases with terms of twelve months or less.
The Company has included extension options in the calculation of lease liabilities where the Company has the right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company does not have any significant termination options and the residual amounts are not material.
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
20 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
|
Total |
|
|
As at December 31, 2019 |
|
143 |
|
Re-measurement (1) |
|
(97 |
) |
Liabilities Settled or Payable |
|
- |
|
As at September 30, 2020 |
|
46 |
|
Less: Current Portion |
|
20 |
|
Long-Term Portion |
|
26 |
|
(1) |
Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings. |
In connection with the acquisition (the “Acquisition”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. There are no maximum payment terms. As at September 30, 2020, no amount was payable under this agreement (December 31, 2019 – $14 million).
21. ONEROUS CONTRACT PROVISIONS
|
Total |
|
|
As at December 31, 2019 |
|
63 |
|
Liabilities Settled |
|
(14 |
) |
Change in Assumptions |
|
5 |
|
Change in Discount Rate |
|
(5 |
) |
Unwinding of Discount on Onerous Contract Provisions |
|
2 |
|
As at September 30, 2020 |
|
51 |
|
Less: Current Portion |
|
18 |
|
Long-Term Portion |
|
33 |
|
The provision for onerous contracts relates to the non-lease components of the Company’s real estate contracts consisting of operating costs and unreserved parking. The provision represents the present value of the difference between the future payments that Cenovus is obligated to make under the non-cancellable contracts and the estimated sublease recoveries, discounted at a credit-adjusted risk-free rate between 6.0 percent and 7.4 percent. The onerous contract provision is expected to be settled in periods up to and including the year 2040. The estimate may vary as a result of changes in the use of the leased office space and sublease arrangements, where applicable.
22. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal.
The aggregate carrying amount of the obligation is:
|
Total |
|
|
As at December 31, 2019 |
|
1,235 |
|
Liabilities Incurred |
|
5 |
|
Liabilities Settled |
|
(36 |
) |
Change in Discount Rate |
|
(371 |
) |
Unwinding of Discount on Decommissioning Liabilities (Note 6) |
|
43 |
|
Foreign Currency Translation |
|
1 |
|
As at September 30, 2020 |
|
877 |
|
The undiscounted amount of the estimated future cash flows required to settle the obligation has been discounted using a credit-adjusted risk-free rate of 6.7 percent as at September 30, 2020 (December 31, 2019 – 4.9 percent). The discount rate increased primarily due to a change in the Company’s credit rating as a result of the current economic environment.
As at |
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Employee Long-Term Incentives |
|
22 |
|
|
|
103 |
|
Pension and Other Post-Employment Benefit Plan |
|
84 |
|
|
|
73 |
|
Other |
|
23 |
|
|
|
19 |
|
|
|
129 |
|
|
|
195 |
|
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
21 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles.
B) Issued and Outstanding
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||||||||||
As at |
Number of Common Shares (thousands) |
|
|
Amount |
|
|
Number of Common Shares (thousands) |
|
|
Amount |
|
||||
Outstanding, Beginning of Year |
|
1,228,828 |
|
|
|
11,040 |
|
|
|
1,228,790 |
|
|
|
11,040 |
|
Common Shares Issued Under Stock Option Plan (Note 26) |
|
42 |
|
|
|
- |
|
|
|
38 |
|
|
|
- |
|
Outstanding, End of Period |
|
1,228,870 |
|
|
|
11,040 |
|
|
|
1,228,828 |
|
|
|
11,040 |
|
There were no preferred shares outstanding as at September 30, 2020 (December 31, 2019 – nil).
As at September 30, 2020, there were 27 million (December 31, 2019 – 26 million) common shares available for future issuance under the stock option plan.
25. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
|
Defined Benefit Pension Plan |
|
|
Private Equity Instruments |
|
|
Foreign Currency Translation Adjustment |
|
|
Total |
|
||||
As at December 31, 2018 |
|
(7 |
) |
|
|
15 |
|
|
|
1,030 |
|
|
|
1,038 |
|
Other Comprehensive Income (Loss), Before Tax |
|
(9 |
) |
|
|
3 |
|
|
|
(142 |
) |
|
|
(148 |
) |
Income Tax Expense |
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
As at September 30, 2019 |
|
(14 |
) |
|
|
18 |
|
|
|
888 |
|
|
|
892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2019 |
|
(2 |
) |
|
|
27 |
|
|
|
802 |
|
|
|
827 |
|
Other Comprehensive Income (Loss), Before Tax |
|
(4 |
) |
|
|
1 |
|
|
|
127 |
|
|
|
124 |
|
Income Tax Expense |
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
As at September 30, 2020 |
|
(5 |
) |
|
|
28 |
|
|
|
929 |
|
|
|
952 |
|
26. STOCK-BASED COMPENSATION PLANS
Cenovus has a number of stock-based compensation plans which include stock options with associated NSRs, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). The following tables summarize information related to Cenovus’s stock-based compensation plans:
|
Units Outstanding |
|
|
Units Exercisable |
|
||
As at September 30, 2020 |
(thousands) |
|
|
(thousands) |
|
||
NSRs |
|
30,795 |
|
|
|
20,576 |
|
PSUs |
|
8,355 |
|
|
|
- |
|
RSUs |
|
8,873 |
|
|
|
- |
|
DSUs |
|
1,502 |
|
|
|
1,502 |
|
The weighted average exercise price of NSRs outstanding as at September 30, 2020 was $18.59.
|
Units Granted |
|
|
Units Vested and Exercised/ Paid Out |
|
||
For the nine months ended September 30, 2020 |
(thousands) |
|
|
(thousands) |
|
||
NSRs |
|
5,783 |
|
|
|
42 |
|
PSUs |
|
2,784 |
|
|
|
1,096 |
|
RSUs |
|
2,678 |
|
|
|
2,172 |
|
DSUs |
|
291 |
|
|
|
60 |
|
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
22 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
In the nine months ended September 30, 2020, 42 thousand NSRs, with a weighted average exercise price of $9.48, were exercised and net settled for cash (Note 24).
The following table summarizes the stock-based compensation expense (recovery) recorded for all plans:
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
NSRs |
|
3 |
|
|
|
2 |
|
|
|
9 |
|
|
|
7 |
|
PSUs |
|
(2 |
) |
|
|
4 |
|
|
|
(9 |
) |
|
|
6 |
|
RSUs |
|
(3 |
) |
|
|
11 |
|
|
|
(8 |
) |
|
|
24 |
|
DSUs |
|
(1 |
) |
|
|
3 |
|
|
|
(7 |
) |
|
|
8 |
|
Stock-Based Compensation Expense (Recovery) |
|
(3 |
) |
|
|
20 |
|
|
|
(15 |
) |
|
|
45 |
|
Stock-Based Compensation Costs Capitalized |
|
1 |
|
|
|
6 |
|
|
|
(4 |
) |
|
|
15 |
|
Total Stock-Based Compensation |
|
(2 |
) |
|
|
26 |
|
|
|
(19 |
) |
|
|
60 |
|
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, net investment in finance leases, accounts payable and accrued liabilities, risk management assets and liabilities, private equity investments, long-term receivables, lease liabilities, contingent payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.
A) Fair Value of Non-Derivative Financial Instruments
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.
The fair values of long-term receivables and net investment in finance leases approximate their carrying amount due to the specific non-tradeable nature of these instruments.
Long-term debt is carried at amortized cost. The estimated fair value of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at September 30, 2020, the carrying value of Cenovus’s long-term debt was $7,797 million and the fair value was $7,307 million (December 31, 2019 carrying value – $6,699 million, fair value – $7,610 million).
Equity investments classified at FVOCI comprise equity investments in private companies. The Company classifies certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available.
The following table provides a reconciliation of changes in the fair value of private equity investments classified at FVOCI:
|
Total |
|
|
As at December 31, 2019 |
|
52 |
|
Change in Fair Value (1) |
|
1 |
|
As at September 30, 2020 |
|
53 |
|
(1) |
Changes in fair value are recorded in other comprehensive income (loss). |
B) Fair Value of Risk Management Assets and Liabilities
The Company’s risk management assets and liabilities consist of crude oil swaps, futures and, if entered into, options, condensate futures and swaps, foreign exchange swaps, interest rate swaps and cross currency interest rate swaps. Crude oil, condensate and, if entered into, natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and the fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including interest rate yield curves (Level 2). The fair value of cross currency interest rate swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
23 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
Summary of Unrealized Risk Management Positions
|
September 30, 2020 |
|
|
December 31, 2019 |
|
||||||||||||||||||
|
Risk Management |
|
|
Risk Management |
|
||||||||||||||||||
As at |
Asset |
|
|
Liability |
|
|
Net |
|
|
Asset |
|
|
Liability |
|
|
Net |
|
||||||
Crude Oil and Condensate |
|
3 |
|
|
|
6 |
|
|
|
(3 |
) |
|
|
5 |
|
|
|
2 |
|
|
|
3 |
|
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:
As at |
September 30, 2020 |
|
|
December 31, 2019 |
|
||
Level 2 – Prices Sourced From Observable Data or Market Corroboration |
|
(3 |
) |
|
|
3 |
|
Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.
The following table summarizes the changes in the fair value of Cenovus’s risk management assets and liabilities:
|
Total |
|
|
As at December 31, 2019 |
|
3 |
|
Fair Value of Contracts Realized During the Period |
|
226 |
|
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Period |
|
(233 |
) |
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts |
|
1 |
|
As at September 30, 2020 |
|
(3 |
) |
C) Fair Value of Contingent Payment
The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian to U.S. foreign exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 3.7 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which consists of individuals who are knowledgeable and have experience in fair value techniques. As at September 30, 2020, the fair value of the contingent payment was estimated to be $46 million (December 31, 2019 – $143 million).
As at September 30, 2020, average WCS forward pricing for the remaining term of the contingent payment is $37.41 per barrel. The average implied volatility of WTI options and the Canadian to U.S. foreign exchange rate options used to value the contingent payment were 37.5 percent and 6.8 percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:
As at September 30, 2020 |
Sensitivity Range |
|
Increase |
|
|
Decrease |
|
||
WCS Forward Prices |
± $5.00 per barrel |
|
|
(43 |
) |
|
|
27 |
|
WTI Option Volatility |
± five percent |
|
|
(17 |
) |
|
|
15 |
|
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility |
± five percent |
|
|
7 |
|
|
|
(9 |
) |
D) Earnings Impact of (Gain) Loss From Risk Management Positions
|
Three Months Ended |
|
|
Nine Months Ended |
|
||||||||||
For the periods ended September 30, |
|
2020 |
|
|
|
2019 |
|
|
|
2020 |
|
|
|
2019 |
|
Realized (Gain) Loss (1) |
|
138 |
|
|
|
(9 |
) |
|
|
226 |
|
|
|
24 |
|
Unrealized (Gain) Loss (2) |
|
(135 |
) |
|
|
9 |
|
|
|
7 |
|
|
|
157 |
|
(Gain) Loss on Risk Management |
|
3 |
|
|
|
- |
|
|
|
233 |
|
|
|
181 |
|
(1) |
Realized gain and loss on risk management are recorded in the reportable segment to which the derivative instrument relates. |
(2) |
Unrealized gain and loss on risk management are recorded in the Corporate and Eliminations segment. |
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
24 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk.
A) Commodity Price, Interest Rate and Foreign Currency Risk
To manage exposure to interest rate volatility, the Company may periodically enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at September 30, 2020, there were no interest rate, foreign exchange or cross currency interest rate swap contracts outstanding.
To manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus, the Company may periodically enter into financial positions as a part of ongoing operations to market the Company’s production and physical inventory positions of crude oil and condensate volumes. The Company has entered into risk management positions to help capture the incremental margin expected to be received in future periods at the time products will be sold. To mitigate overall exposure to the fluctuations in commodity prices, the Company may also enter into financial positions to protect the near-term and future cash flows. As at September 30, 2020, the fair value of financial positions was a net liability of $3 million and consisted of crude oil and condensate instruments.
Net Fair Value of Risk Management Positions
As at September 30, 2020 |
Notional Volumes (1) (2) |
|
Terms (3) |
|
Weighted Average Price (1) (2) |
|
Fair Value Asset (Liability) |
|
||||
Crude Oil and Condensate Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
WTI Fixed - Sell |
107,066 bbls/d |
|
|
October 2020 - March 2021 |
|
|
US$38.82/bbl |
|
|
|
(43 |
) |
WTI Fixed - Buy |
65,533 bbls/d |
|
|
October 2020 - March 2021 |
|
|
US$37.90/bbl |
|
|
|
40 |
|
WCS (Alberta) Differential - Sell |
14,338 bbls/d |
|
|
November 2020 - March 2021 |
|
|
US($13.80)/bbl |
|
|
|
(6 |
) |
WCS (Alberta) Differential - Buy |
7,782 bbls/d |
|
|
November 2020 - December 2021 |
|
|
US($13.45)/bbl |
|
|
|
3 |
|
WCS (Houston) Differential - Sell |
3,444 bbls/d |
|
|
November 2020 - March 2021 |
|
|
US($3.25)/bbl |
|
|
|
- |
|
WCS (Houston) Differential - Buy |
1,000 bbls/d |
|
|
January 2021 - March 2021 |
|
|
US($3.60)/bbl |
|
|
|
- |
|
Belvieu Fixed - Sell |
1,359 bbls/d |
|
|
October 2020 - December 2020 |
|
|
US$36.77/bbl |
|
|
|
- |
|
Belvieu Fixed - Buy |
8,043 bbls/d |
|
|
October 2020 - December 2020 |
|
|
US$35.94/bbl |
|
|
|
1 |
|
Condensate Differential - Buy |
2,371 bbls/d |
|
|
November 2020 - March 2021 |
|
|
US($3.45)/bbl |
|
|
|
2 |
|
Other Financial Positions (4) |
|
|
|
|
|
|
|
|
|
|
- |
|
Total Fair Value |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
(1) |
Barrels per day (“bbls/d”). Barrel (“bbl”). |
(2) |
Notional volumes and weighted average prices represent for various contracts over the respective terms. The notional volumes and weighted average prices may fluctuate from month to month as it represents the averages for various individual contracts with different terms. |
(3) |
Contract terms represents averages for various individual contracts with different terms and range from one to fourteen months. |
(4) |
Other financial positions consist of risk management positions related to natural gas contracts and the Company’s Refining and Marketing segment. |
Sensitivities
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.
The impact of fluctuating commodity prices and foreign exchange on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:
|
Sensitivity Range |
|
Increase |
|
|
Decrease |
|
||
Crude Oil Commodity Price |
± US$5.00 per barrel Applied to WTI and Condensate Hedges |
|
|
(47 |
) |
|
|
47 |
|
Crude Oil Differential Price |
± US$2.50 per barrel Applied to Differential Hedges Tied to Production |
|
|
(1 |
) |
|
|
1 |
|
B) Credit Risk
Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee and the Board of Directors designed to ensure that its credit exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.
Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, net investment in finance leases, risk management assets and long-term receivables is the total carrying value.
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
25 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
As at September 30, 2020, approximately 95 percent of the Company’s accruals, joint operations, trade receivables and net investment in finance leases were investment grade, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The average expected credit loss on the Company’s accruals, joint operations, trade receivables and net investment in finance leases was 0.8 percent as at September 30, 2020 (December 31, 2019 – 0.3 percent).
C) Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 18, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt position.
Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn capacity on its committed credit facilities and uncommitted demand facilities as well as availability under its base shelf prospectus. As at September 30, 2020, Cenovus had $404 million in cash and cash equivalents, $5.6 billion available on its committed credit facilities, $1.1 billion available on its uncommitted demand facilities, of which $600 million may be drawn for general purposes, or the full amount can be available to issue letters of credit. A further US$47 million representing the Company's available proportionate share of the WRB uncommitted demand facilities is available. In addition, Cenovus has unused capacity of US$4.0 billion under its base shelf prospectus, the availability of which is dependent on market conditions.
Undiscounted cash outflows relating to financial liabilities are:
As at September 30, 2020 |
Less than 1 Year |
|
|
Years 2 and 3 |
|
|
Years 4 and 5 |
|
|
Thereafter |
|
|
Total |
|
|||||
Accounts Payable and Accrued Liabilities |
|
1,549 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,549 |
|
Short-Term Borrowings (1) |
|
137 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
137 |
|
Risk Management Liabilities (2) |
|
6 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6 |
|
Long-Term Debt (1) |
|
403 |
|
|
|
2,059 |
|
|
|
2,060 |
|
|
|
9,178 |
|
|
|
13,700 |
|
Contingent Payment (3) |
|
20 |
|
|
|
28 |
|
|
|
- |
|
|
|
- |
|
|
|
48 |
|
Lease Liabilities (1) |
|
267 |
|
|
|
465 |
|
|
|
397 |
|
|
|
1,447 |
|
|
|
2,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2019 |
Less than 1 Year |
|
|
Years 2 and 3 |
|
|
Years 4 and 5 |
|
|
Thereafter |
|
|
Total |
|
|||||
Accounts Payable and Accrued Liabilities |
|
2,210 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,210 |
|
Risk Management Liabilities (2) |
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
Long-Term Debt (1) |
|
344 |
|
|
|
1,338 |
|
|
|
1,465 |
|
|
|
9,326 |
|
|
|
12,473 |
|
Contingent Payment |
|
79 |
|
|
|
69 |
|
|
|
- |
|
|
|
- |
|
|
|
148 |
|
Lease Liabilities (1) |
|
277 |
|
|
|
466 |
|
|
|
410 |
|
|
|
1,544 |
|
|
|
2,697 |
|
(1) |
Principal and interest, including current portion if applicable. |
(2) |
Risk management liabilities subject to master netting agreements. |
(3) |
Refer to Note 27C for fair value assumptions. |
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
26 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
29. SUPPLEMENTARY CASH FLOW INFORMATION
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
|
Dividends Payable |
|
|
Short-Term Borrowings |
|
|
Long-Term Debt |
|
|
Lease Liabilities |
|
||||
As at January 1, 2019 |
|
- |
|
|
|
- |
|
|
|
9,164 |
|
|
|
1,494 |
|
Changes From Financing Cash Flows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Paid |
|
(183 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Net Issuance (Repayment) of Long-Term Debt |
|
- |
|
|
|
- |
|
|
|
(1,601 |
) |
|
|
- |
|
Net Issuance (Repayment) of Revolving Long-Term Debt |
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
- |
|
Principal Repayment of Leases |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(108 |
) |
Non-Cash Changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared |
|
183 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Foreign Exchange (Gain) Loss |
|
- |
|
|
|
- |
|
|
|
(264 |
) |
|
|
(7 |
) |
Lease Additions |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
311 |
|
Lease Terminations |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(11 |
) |
Gain on Repurchase of Debt and Amortization of Debt Issuance Costs |
|
- |
|
|
|
- |
|
|
|
(67 |
) |
|
|
- |
|
Other |
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
- |
|
As at September 30, 2019 |
|
- |
|
|
|
- |
|
|
|
7,239 |
|
|
|
1,679 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2019 |
|
- |
|
|
|
- |
|
|
|
6,699 |
|
|
|
1,916 |
|
Changes From Financing Cash Flows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Paid |
|
(77 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Net Issuance (Repayment) of Short-Term Borrowings |
|
- |
|
|
|
133 |
|
|
|
- |
|
|
|
- |
|
Issuance of Long-Term Debt |
|
- |
|
|
|
- |
|
|
|
1,326 |
|
|
|
- |
|
(Repayment) of Long-Term Debt |
|
- |
|
|
|
- |
|
|
|
(112 |
) |
|
|
- |
|
Net Issuance (Repayment) of Revolving Long-Term Debt |
|
- |
|
|
|
- |
|
|
|
(220 |
) |
|
|
- |
|
Principal Repayment of Leases |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(149 |
) |
Non-Cash Changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared |
|
77 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Foreign Exchange (Gain) Loss |
|
- |
|
|
|
4 |
|
|
|
127 |
|
|
|
17 |
|
Gain on Repurchase of Debt and Amortization of Debt Issuance Costs |
|
- |
|
|
|
- |
|
|
|
(22 |
) |
|
|
- |
|
Lease Additions |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
48 |
|
Lease Terminations |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
Lease Modifications |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(3 |
) |
Re-measurement of Lease Liabilities |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
Other |
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
As at September 30, 2020 |
|
- |
|
|
|
137 |
|
|
|
7,797 |
|
|
|
1,833 |
|
30. COMMITMENTS AND CONTINGENCIES
A) Commitments
Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements. In addition, the Company has commitments related to its risk management program and an obligation to fund its defined benefit pension and other post-employment benefit plans. Additional information related to the Company’s commitments can be found in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2019.
As at September 30, 2020, total commitments were $23 billion, of which $22 billion were for various transportation and storage commitments. Transportation commitments include $14 billion (December 31, 2019 – $13 billion) that are subject to regulatory approval or have been approved but are not yet in service. Terms are up to 20 years subsequent to the date of commencement and should help align with the Company’s future transportation requirements with anticipated production growth.
As at September 30, 2020, there were outstanding letters of credit aggregating $457 million issued as security for performance under certain contracts (December 31, 2019 – $364 million).
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
27 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the periods ended September 30, 2020
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.
Contingent Payment
In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. As at September 30, 2020, the estimated fair value of the contingent payment was $46 million (see Note 20).
Husky Merger
On October 25, 2020, Cenovus and Husky Energy Inc. (TSX: HSE) announced that they have entered into a definitive agreement to combine the companies in an all-stock transaction to create a new integrated Canadian oil and natural gas company. Upon completion of the transaction, which will require shareholder and regulatory approval, the combined entity will operate as Cenovus.
Cenovus Energy Inc. – Q3 2020 Interim Consolidated Financial Statements |
28 |
Exhibit 99.4
CENOVUS ENERGY INC.
Supplemental Financial Information (unaudited)
Exhibit to the September 30, 2020 Interim Consolidated Financial Statements
Consolidated Interest Coverage Ratios
The following financial ratios are provided by Cenovus Energy Inc. (the “Company”) in connection with the offering of common shares, debt securities, preferred shares, subscription receipts, warrants, share purchase contracts and/or units of the Company by way of base shelf prospectus dated September 19, 2019. These ratios are based on the Company's consolidated financial statements that are prepared in accordance with International Financial Reporting Standards, which are generally accepted in Canada.
Interest coverage ratios for the twelve months ended September 30, 2020
|
(times) |
Net earnings available for all interest bearing financial liabilities (1)
|
(5.3)x |
Net earnings available for all interest bearing financial liabilities before unrealized (gains) and losses on risk management activities (2) |
(5.3)x |
(1) |
Calculated as net earnings plus income tax and borrowing costs on all interest bearing financial liabilities; divided by borrowing costs on all interest bearing financial liabilities. |
(2) |
Calculated as net earnings plus income tax and borrowing costs on all interest bearing financial liabilities before unrealized (gains) and losses on risk management activities; divided by borrowing costs on all interest bearing financial liabilities. |
The Company believes the interest coverage ratio based on net earnings available for all interest bearing financial liabilities before unrealized (gains) and losses on risk management activities is a relevant measure for investors as the realization of unrealized (gains) and losses are yet to be determined and will be realized in future periods.
Exhibit 99.5
CERTIFICATION OF INTERIM FILINGS
I, Alex J. Pourbaix, President & Chief Executive Officer of Cenovus Energy Inc., certify the following:
1. |
Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Cenovus Energy Inc. (the “issuer”) for the interim period ended September 30, 2020. |
2. |
No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings. |
3. |
Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings. |
4. |
Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52‑109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer. |
5. |
Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings |
|
(a) |
designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
|
(i) |
material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
|
(ii) |
information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
|
(b) |
designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 |
Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework. |
5.2 |
ICFR - material weakness relating to design: N/A |
5.3 |
Limitation on scope of design: N/A |
6. |
Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2020 and ended on September 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR. |
/s/ Alex J. Pourbaix |
|
Alex J. Pourbaix |
|
President & Chief Executive Officer |
Exhibit 99.6
CERTIFICATION OF INTERIM FILINGS
I, Jonathan M. McKenzie, Executive Vice-President & Chief Financial Officer of Cenovus Energy Inc., certify the following:
1. |
Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Cenovus Energy Inc. (the “issuer”) for the interim period ended September 30, 2020. |
2. |
No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings. |
3. |
Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings. |
4. |
Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52‑109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer. |
5. |
Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings |
|
(a) |
designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
|
(i) |
material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
|
(ii) |
information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
|
(b) |
designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 |
Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework. |
5.2 |
ICFR - material weakness relating to design: N/A |
5.3 |
Limitation on scope of design: N/A |
6. |
Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2020 and ended on September 30, 2020 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR. |
/s/ Jonathan M. McKenzie |
|
|
Jonathan M. McKenzie |
|
|
Executive Vice-President & Chief Financial Officer |