UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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[X] |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2018
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-15226
ENCANA CORPORATION
(Exact name of registrant as specified in its charter)
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Canada |
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98-0355077 |
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(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
Suite 4400, 500 Centre Street S.E., P.O. Box 2850, Calgary, Alberta, Canada, T2P 2S5
(Address of principal executive offices)
Registrant’s telephone number, including area code (403) 645-2000
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class |
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Name of each exchange on which registered |
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Common Shares |
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 2 29 .405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [X] Accelerated filer [ ]
Non-accelerated filer [ ] Smaller reporting company [ ]
Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):
Yes [ ] No [X]
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Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 29, 2018 |
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12,480,296,717 |
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Number of registrant’s common shares outstanding as of February 25, 2019 |
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1,495,871,408 |
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Documents Incorporated by Reference
Portions of registrant’s definitive proxy statement (“Proxy Statement”) for the registrant’s 2019 annual meeting of shareholders to be held April 30, 2019 (to be filed with the Securities and Exchange Commission prior to April 30, 2019) are incorporated by reference in Part III of this Annual Report on Form 10-K.
FORM 10-K
TABLE OF CONTENTS
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Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Encana” and the “Company” refer to Encana Corporation and its consolidated subsidiaries. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:
“AECO” means Alberta Energy Company and is the Canadian benchmark price for natural gas.
“ASC” means Accounting Standards Codification.
“ASU” means Accounting Standards Update.
“bbl” or “bbls” means barrel or barrels.
“bbls/d” means barrels per day.
“Bcf” means billion cubic feet.
“Bcf/d” means billion cubic feet per day.
“BOE” means barrels of oil equivalent.
“BOE/d” means barrels of oil equivalent per day.
“Btu” means British thermal units, a measure of heating value.
“DD&A” means depreciation, depletion and amortization expenses.
“FASB” means Financial Accounting Standards Board.
“LIBOR” means London Interbank Offered Rate.
“Mbbls” means thousand barrels.
“Mbbls/d” means thousand barrels per day.
“MBOE” means thousand barrels of oil equivalent.
“MBOE/d” means thousand barrels of oil equivalent per day.
“Mcf” means thousand cubic feet.
“Mcf/d” means thousand cubic feet per day.
“MD&A” means Management’s Discussion and Analysis of Financial Condition and Results of Operations.
“MMbbls” means million barrels.
“MMbbls/d” means million barrels per day.
“MMBOE” means million barrels of oil equivalent.
“MMBOE/d” means million barrels of oil equivalent per day.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“MMcf/d” means million cubic feet per day.
“NCIB” means normal course issuer bid.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“NYSE” means New York Stock Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“SEC” means United States Securities and Exchange Commission.
“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.
“S&P 500” means Standard and Poor’s 500 index.
“ S&P/TSX Composite Index ” means Standard and Poor’s index for Canadian equity markets.
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“TSX” means Toronto Stock Exchange.
“U.S.” or “United States” or “USA” means United States of America.
“U.S. GAAP” means U.S. Generally Accepted Accounting Principles.
“WTI” means West Texas Intermediate.
CONVERSIONS
In this Annual Report on Form 10-K, a conversion of natural gas volumes to BOE is on the basis of six Mcf to one bbl. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value, particularly if used in isolation.
CONVENTIONS
Unless otherwise specified, all dollar amounts are expressed in U.S. dollars, all references to “dollars”, “$” or “US$” are to U.S. dollars and all references to “C$” are to Canadian dollars. All amounts are provided on a before tax basis, unless otherwise stated. In addition, all information provided herein is presented on an after royalties basis.
The term “liquids” is used to represent oil, NGLs and condensate. The term “liquids rich” is used to represent natural gas streams with associated liquids volumes. The term “play” is used to describe an area in which hydrocarbon accumulations or prospects of a given type occur. Encana’s focus of development is on hydrocarbon accumulations known to exist over a large areal expanse and/or thick vertical section and are developed using hydraulic fracturing. This type of development typically has a lower geological and/or commercial development risk and lower average decline rate, when compared to conventional development.
The term “core asset” refers to plays that are the focus of the Company’s current capital investment and development plan. The Company continually reviews funding for development of its plays based on strategic fit, profitability and portfolio diversity and, as such, the composition of plays identified as a core asset may change over time.
References to information contained on the Company’s website at www.encana.com are not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
FORWARD-LOOKING STATEMENTS AND RISK
This Annual Report on Form 10-K and documents incorporated herein by reference contain certain forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements include: composition of the Company’s core assets, including the allocation of capital and focus of development plans; growth in long-term shareholder value; vision of being a leading North American resource play company; the anticipated synergies from the Newfield acquisition; the expectation that the Newfield acquisition will be accretive to all metrics in the Company’s five-year plan; the Company’s ability to realize the anticipated benefits of the Newfield acquisition; statements with respect to the Company’s strategic objectives including capital allocation strategy, focus of investment, focus of returning capital to shareholders through sustainable dividends and share buybacks, growth of high margin liquids volumes, operating and capital efficiencies and ability to preserve balance sheet strength; ability to lower costs and improve efficiencies to achieve competitive advantage, including benefits of integrated supply chain model and self-sourcing; ability to repeat and deploy successful practices across the Company’s multi-basin portfolio; balancing commodity portfolio; anticipated commodity prices; success of and benefits from technology and innovation, including cube development approach, precision well targeting and advanced completion designs; reduced dependence on fresh water requirements and anticipated water infrastructure; ability to accelerate activity levels; ability to optimize well and completion designs, including changes to lateral lengths drilled, stage, well spacing and stacking optimization; future well inventory; anticipated drilling, number of drilling rigs and the success thereof; anticipated drilling costs and cycle times; anticipated proceeds and future benefits from various joint venture, partnership and other agreements; expected timing for construction of facilities
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and costs thereof; expansion of future midstream services; estimates of reserves and resources; expected production and product types; ability to replicate successful test wells to future production; statements regarding anticipated cash flow, non-GAAP cash flow margin and leverage ratios; anticipated cash and cash equivalents; anticipated hedging and outcomes of risk management program, including ability to leverage marketing fundamentals expertise, exposure to certain commodity prices and foreign exchange, amount of hedged production, market access and physical sales locations; impact of changes in laws and regulations, including recent U.S. tax reform and potential changes to free trade agreements; compliance with environmental legislation and claims related to the purported causes and impact of climate change, and the costs therefrom; adequacy of provisions for abandonment and site reclamation costs; financial flexibility and discipline; access to cash and cash equivalents and other methods of funding; ability to meet financial obligations, manage debt and financial ratios, finance growth and compliance with financial covenants; impact to the Company as a result of changes to its credit rating; access to the Company's credit facilities; planned annualized dividend and the declaration and payment of future dividends, if any; intention to guarantee Newfield’s outstanding notes; managing capital structure including adjustments to capital spending or dividends, issuing debt or equity, purchasing shares through a NCIB or repaying existing debt; expectations with respect to the Company’s anticipated share buyback, including amount and number of shares to be acquired, anticipated timeframe, method and location of purchases, and source of funding thereof; adequacy of the Company's provision for taxes and legal claims; projections and expectation of meeting the targets contained in the Company's corporate guidance and five-year plan; ability to manage cost inflation and expected cost structures, including expected operating, transportation and processing and administrative expenses; competitiveness and pace of growth of the Company’s assets within North America and against its peers; outlook of oil and gas industry generally and impact of geopolitical environment; returns from the Company’s core assets; anticipated capital spending plans and source of funding thereof; anticipated staffing levels; expected future interest expense; the Company’s commitments and obligations and ability to satisfy the same; statements with respect to future ceiling test impairments; and the possible impact and timing of accounting pronouncements, rule changes and standards.
Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; ability to access credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance, five-year plan and as specified herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of the Company's drive to productivity and efficiencies; results from innovations; expectation that counterparties will fulfill their obligations under the gathering, midstream and marketing agreements; access to transportation and processing facilities where Encana operates; assumed tax, royalty and regulatory regimes; and expectations and projections made in light of, and generally consistent with, Encana's historical experience and its perception of historical trends, including with respect to the pace of technological development, benefits achieved and general industry expectations.
Risks and uncertainties that may affect these outcomes include: ability to generate sufficient cash flow to meet obligations; commodity price volatility; ability to secure adequate transportation and potential pipeline curtailments; variability and discretion of Encana's board of directors (the “Board of Directors”) to declare and pay dividends, if any; timing and costs of well, facilities and pipeline construction; business interruption, property and casualty losses or unexpected technical difficulties, including impact of weather; counterparty and credit risk; ability to realize the anticipated benefits of acquisitions, including the Newfield acquisition; uncertainties relating to the Company’s ability to successfully integrate Newfield’s business, technologies, personnel and business partners; actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls; sustained declines in commodity prices resulting in impairment of assets; impact of a downgrade in credit rating and its impact on access to sources of liquidity; fluctuations in currency and interest rates; risks associated with inflation rates; risks inherent in the Company's corporate guidance; failure to achieve cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology, including electronic, cyber and physical security breaches; changes in or interpretation of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations, including potential environmental liabilities that are not covered by an effective indemnity or insurance; risks associated with existing and potential lawsuits and regulatory actions made against the Company, including in relation to the Newfield acquisition; impact of disputes arising with its partners, including suspension of certain obligations and inability to dispose of assets or interests in certain arrangements; the Company's ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities, including future net revenue estimates; land, legal, regulatory and ownership complexities inherent in Canada, the
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U.S. and China; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as “partnerships” or “joint ventures” and the funds received in respect thereof which Encana may refer to from time to time as “proceeds”, “deferred purchase price” and/or “carry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks described in Item 1A. Risk Factors of this Annual Report on Form 10-K and risks and uncertainties impacting Encana's business as described from time to time in the Company's other periodic filings with the SEC incorporated by reference in this Annual Report on Form 10-K.
Although the Company believes the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above and in the documents incorporated by reference herein are not exhaustive. Forward-looking statements are made as of the date of this document (or, in the case of a document incorporated by reference, the date of such document incorporated by reference) and, except as required by law, the Company undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained or incorporated by reference in this Annual Report on Form 10-K are expressly qualified by these cautionary statements.
The reader should read carefully the risk factors described in Item 1A. Risk Factors of this Annual Report on Form 10-K and the documents incorporated by reference in this Annual Report on Form 10-K for a description of certain risks that could, among other things, cause actual results to differ from these forward-looking statements.
EXPLANATORY NOTE
On February 13, 2019, Encana completed its previously announced strategic business combination with Newfield Exploration Company (“Newfield”) pursuant to which an indirect, wholly-owned subsidiary of Encana merged with and into Newfield, with Newfield surviving the merger as an indirect, wholly-owned subsidiary of Encana (the “Newfield acquisition”). Although this Annual Report on Form 10-K is filed after completion of the acquisition, unless otherwise specifically noted herein, information set forth herein only relates to the period as at and for the fiscal year ended December 31, 2018 and therefore does not include the information of Newfield for such periods. Accordingly, unless otherwise specifically noted herein, references herein to “Encana,” the “Company,” “we,” “us,” or “our” refer only to Encana and its subsidiaries prior to the Newfield acquisition and do not include Newfield and its subsidiaries.
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Items 1 and 2. Business and Properties
GENERAL
Encana is a leading North American energy producer that is focused on generating full-cycle returns, free cash flow and return of capital to shareholders by developing its multi-basin portfolio of oil, NGL and natural gas producing plays. Encana's operations also include the marketing of oil, NGLs and natural gas. As at December 31, 2018, all of Encana’s reserves and production were located in North America.
Encana’s registered and principal office is located at 4400, 500 Centre Street S.E., Calgary, Alberta T2P 2S5, Canada. Encana’s common shares are listed and posted for trading on the TSX and on the NYSE under the symbol “ECA”. Encana is incorporated under the Canada Business Corporations Act (the “CBCA”) and was formed in 2002 through the business combination of two predecessor companies.
Available Information
Encana is subject to the informational requirements of the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”) and, in accordance with the Exchange Act, it also files reports with and furnishes other information to the SEC. The public may obtain any document Encana files with or furnishes to the SEC from the SEC's Electronic Document Gathering, Analysis, and Retrieval system (“EDGAR”), which can be accessed at www.sec.gov , or via the System for Electronic Document Analysis and Retrieval (“SEDAR”), which can be accessed at www.sedar.com, as well as from commercial document retrieval services.
Copies of this Annual Report on Form 10-K and the documents incorporated herein by reference may be obtained on request without charge from Encana’s Corporate Secretary, 4400, 500 Centre Street S.E., P.O. Box 2850, Calgary, Alberta T2P 2S5, Canada, telephone: (403) 645-2000. Encana also provides access without charge to all of the Company’s SEC filings, including copies of this Annual Report on Form 10-K and the documents incorporated herein by reference, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after filing or furnishing, on Encana’s website located at www.encana.com .
Enforceability of Civil Liabilities
Encana is a corporation incorporated under and governed by the CBCA. Some of Encana’s officers and directors, and some of the experts named in this Annual Report on Form 10-K, are Canadian residents, and many of Encana’s assets or the assets of its officers and directors and the experts are located outside the United States. Encana has appointed an agent for service of process in the United States, but it may be difficult for holders of common shares who reside in the United States to effect service within the United States upon those directors, officers and experts who are not residents of the United States. It may also be difficult for holders of common shares who reside in the United States to realize in the United States upon judgments of courts of the United States predicated upon our civil liability and the civil liability of our officers and directors and experts under the United States federal securities laws.
STRATEGY
Encana’s vision is to be a leading North American resource play company that is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. Objectives that support the execution of the Company’s strategy include:
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Balance sheet strength |
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Disciplined capital allocation |
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Maximizing profitability through operational and capital efficiencies |
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Focused on returning capital to shareholders through sustainable dividends and share buybacks |
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Focused investment in high margin liquids plays to drive cash flow, free cash flow and returns from a multi-basin portfolio |
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The Company has a history of identifying and entering into strategic plays that can be developed with industry leading horizontal drilling and completions methods and leveraging technology to profitably develop oil and natural gas resources within the plays. Encana continually strives to lower costs and improve efficiencies to achieve competitive advantage through technology and innovation. Capital and operating efficiencies are achieved by repeating and deploying successful practices across the Company’s multi-basin portfolio.
Encana’s capital investment strategy is focused on quality growth from a limited number of core, high margin and scalable projects, while balancing the commodity portfolio and optimizing performance from the remainder of the Company’s resource base. In addition, Encana leverages its market fundamentals expertise by actively monitoring and managing market volatility and diversifying price and market access risks to enhance the Company’s margins.
During 2018, the oil and natural gas industry continued to experience commodity price volatility, with increasing concerns over global economic growth and continued robust production growth in North America. Encana has continued to execute on its strategy by directing capital investment to core assets with high margin liquids and future growth potential and divesting non-strategic assets. With higher levels of industry activity, Encana focused on maintaining cost controls by leveraging its integrated supply chain model through self-sourcing of key drilling and completions consumables to obtain scale advantages from negotiating better contract pricing and securing supply services. Encana also focused on enhancing capital and operating efficiencies by leveraging technology and innovation to maximize efficiencies and optimize resource recovery. In 2019, Encana is focused on generating free cash flow with modest liquids growth from the Company’s portfolio of top tier assets and delivering return of capital to shareholders. For additional discussion on the Company’s results, see Item 7 of this Annual Report on Form 10-K.
REPORTING SEGMENTS
Encana’s predominant operations are focused on the finding and development of oil, NGLs and natural gas reserves. The Company is also focused on creating and capturing additional value through its market optimization segment. The Company conducts a substantial portion of its business through subsidiaries. Encana’s operating and reportable segments are: (i) Canadian Operations; (ii) USA Operations; and (iii) Market Optimization.
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Canadian Operations includes the exploration for, development of, and production of oil, NGLs, natural gas and other related activities within Canada. At December 31, 2018, core assets that are part of Encana’s strategic development focus include: Montney in northeast British Columbia and northwest Alberta and Duvernay in west central Alberta. Other Upstream Operations comprise assets that are not part of Encana’s current strategic focus and primarily include: Wheatland in southern Alberta, Horn River in northeast British Columbia and Deep Panuke located offshore Nova Scotia. Other Upstream Operations also includes assets where the Company may pursue growth opportunities. |
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USA Operations includes the exploration for, development of, and production of oil, NGLs, natural gas and other related activities within the U.S. At December 31, 2018, core assets that are part of Encana’s strategic development focus include: Eagle Ford in south Texas and Permian in west Texas. Other Upstream Operations comprise assets that are not part of Encana’s current strategic focus. |
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Market Optimization activities are managed by the Midstream, Marketing & Fundamentals team, which is primarily responsible for the sale of the Company’s proprietary production to third party customers and enhancing the associated netback price. Market Optimization activities also include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. |
For additional information regarding Encana’s reporting segments, see Note 2 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
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OIL AND GAS PROPERTIES AND ACTIVITIES
The following map reflects the location of Encana’s North American landholdings and assets as at December 31, 2018 and does not include oil and gas properties that were acquired by Encana pursuant to the Newfield acquisition.
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Overview: In 2018, the Canadian Operations had total capital investment of approximately $632 million and drilled approximately 139 net wells predominately in Montney and Duvernay. Production averaged approximately 49.6 Mbbls/d of oil and NGLs and approximately 1,007 MMcf/d of natural gas. At December 31, 2018, the Canadian Operations had an established land position in Canada of approximately 1.8 million net acres including approximately 1.2 million net undeveloped acres. In addition, the Canadian Operations accounted for 40 percent of production sales during 2018 and 53 percent of total proved reserves as at December 31, 2018.
The following tables summarize the Canadian Operations landholdings, producing wells and daily production as at and for the periods indicated.
Montney
Montney is primarily a condensate rich natural gas play located in northeast British Columbia and northwest Alberta. While Encana is currently targeting the development of condensate rich locations in the Montney formation, the acreage comprising the Montney play also includes landholdings with incremental producing formations such as Cadomin and Doig. In 2018, total production from the play averaged approximately 41.7 Mbbls/d of oil and NGLs and approximately 894 MMcf/d of natural gas. As at December 31, 2018, Encana controlled approximately 793,000 net acres in the play.
During 2018, Encana continued to focus development in the Montney formation, which is characterized by up to six stacked horizons spanning over 1,000 feet of stratigraphy and is being developed exclusively with horizontal well technology. At December 31, 2018, Encana held a large position in the Montney formation of approximately
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486,000 net acres, including 261,000 net undeveloped acres and during the year production averaged approximately 41.5 Mbbls/d of oil and NGLs and approximately 831 MMcf/d of natural gas.
Encana utilized the cube development approach which increased efficiency by reducing cycle times and completion costs. This development approach utilizes large multi-well pads and multiple drilling rigs simultaneously, and advances technology to optimize well spacing and completions intensity. During 2018, Encana reduced completions costs by approximately 17.7 percent, primarily through its use of a centralized water hub and automated well monitoring. In 2018, Encana drilled approximately 128 net horizontal wells with lateral lengths ranging from approximately 3,200 to 12,300 feet and inter-well spacing ranging from approximately 520 to 1,100 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change.
As at December 31, 2018, Encana has access to natural gas processing capacity of approximately 1,300 MMcf/d, of which approximately 1,100 MMcf/d is under contract with third parties under varying terms and duration and approximately 215 MMcf/d is owned by the Company. Encana also has access to gathering and compression capacity of approximately 1,600 MMcf/d, of which approximately 1,500 MMcf/d is under contract with third parties under varying terms and duration and approximately 100 MMcf/d is owned by the Company. During the third quarter of 2018, access to liquids handling capacity increased due to one new facility that provides processing under contract with third parties.
Encana has a partnership agreement with a subsidiary of Mitsubishi Corporation (“Mitsubishi”), the Cutbank Ridge Partnership (“CRP”), to jointly develop certain lands predominately in the Montney formation. Under the agreement, Mitsubishi agreed to invest approximately C$2.9 billion for its 40 percent partnership interest in the CRP, of which the investment has been substantially received as of December 31, 2018. The remaining C$101.7 million is expected to be invested in 2019.
Duvernay
Duvernay is a liquids rich shale gas play located in west central Alberta and includes properties that are primarily located in the Duvernay formation, which extends across the Simonette, Pinto, Edson and Willesden Green properties, but also holds potential in other overlapping formations such as the Montney. As at December 31, 2018, Encana controlled approximately 264,000 net acres, including 219,000 net undeveloped acres in the play.
Encana is currently targeting the development of condensate rich locations in the Simonette area and area overlapping the Montney formation using multi-well pad horizontal drilling technology. During 2018, Encana focused on efficient development to fill existing processing capacity, reducing drilling days and increasing lateral lengths drilled to maximize capital efficiency. Encana drilled approximately 10 net wells during the year with lateral lengths ranging from approximately 9,000 to 12,700 feet with inter-well spacing averaging approximately 1,000 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change. In 2018, production averaged approximately 7.9 Mbbls/d of oil and NGLs and approximately 59 MMcf/d of natural gas.
Encana holds an approximate 50.1 percent ownership in three Simonette natural gas processing plants and the associated gathering and compression, of which Encana’s share of natural gas processing capacity is approximately 103 MMcf/d with NGLs production capacity of approximately 18.0 Mbbls/d.
Other Upstream Operations:
Wheatland
Wheatland is located in southern Alberta and includes producing horizons primarily in the coals and sands of the Cretaceous Edmonton and Belly River Groups. As at December 31, 2018, Encana had approximately 428 net producing wells and controlled approximately 206,000 net acres in the play. In 2018, natural gas production averaged approximately 5 MMcf/d.
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Horn River is located in northeast British Columbia, where development was historically in the Horn River Basin shales (Muskwa, Otter Park and Evie), which are upwards of 500 feet thick. In 2018, Encana’s natural gas production averaged approximately 43 MMcf/d. As at December 31, 2018, Encana had approximately 48 net producing horizontal wells and controlled approximately 164,000 net acres in the Horn River Basin shales. Encana owns an interest in natural gas compression capacity in Horn River of approximately 285 MMcf/d at various facilities in the area. Encana has a take or pay commitment under the Cabin plant natural gas processing arrangement with a third party, which has a remaining term of 15 years.
Deep Panuke
Encana is the owner and operator of the Deep Panuke natural gas field located offshore Nova Scotia, which is approximately 250 kilometres southeast of Halifax on the Scotian shelf. The offshore Production Field Centre (“PFC”) utilized for operations is under a lease arrangement which has an initial term that expires in 2021.
In May 2018, Encana permanently ceased production at Deep Panuke and has begun planning decommissioning activities for the PFC and wells. In June 2018, Encana filed an application with the regulatory authority to abandon and decommission the PFC and related subsea facilities, wells and pipeline.
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Overview: In 2018, the USA Operations had total capital investment of approximately $1,332 million and drilled approximately 170 net wells. Production averaged approximately 89.5 Mbbls/d of oil, approximately 29.0 Mbbls/d of NGLs and approximately 151 MMcf/d of natural gas. At December 31, 2018, the USA Operations had an established land position of approximately 197,000 net acres including approximately 42,000 net undeveloped acres. In addition, the USA Operations accounted for 60 percent of production sales during 2018 and 47 percent of total proved reserves as at December 31, 2018.
During 2018, Encana divested of approximately 182,000 net acres in San Juan located in northwest New Mexico.
The following tables summarize the USA Operations landholdings, producing wells and daily production as at and for the periods indicated.
Eagle Ford
Eagle Ford is a tight oil play located in south Texas in the Karnes and Atascosa counties. The focus is on the development of the thickest portion of the Eagle Ford shale in the Karnes Trough, where Encana holds a largely contiguous position. At December 31, 2018, Encana controlled approximately 42,000 net acres in the play. Encana is focused on developing the lower Eagle Ford, as well as optimizing upper Eagle Ford, Austin Chalk and Graben targets exclusively using horizontal drilling. During 2018, Encana drilled approximately 55 net wells in the area with lateral lengths ranging from approximately 2,000 to 8,000 feet with an average measured total depth of approximately 17,000 feet. Production averaged approximately 28.4 Mbbls/d of oil, approximately 8.4 Mbbls/d of NGLs and approximately 52 MMcf/d of natural gas during the year.
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During 201 8 , Encana continued to focus on precision well targeting, spacing and stacking optimization and improving completions designs . Performance improvements were achieved from employing advanced completion designs, pumping higher volumes of fluid and proppant with tighter cluster spacing of less than 20 feet, resulting in increased well productivity and optimized capital efficiency. In addition, Encana expanded development activity in the Austin Chalk and delineation of Graben , drilling 20 net horizontal wells in 201 8 . As Encana continues to optimize development and apply advanced completions designs, lateral lengths drilled, cluster spacing and well spacing may change. Encana also focused on maintaining cost controls by negotiating better contract pricing, automation of well control, optimizing artificial lift systems and streamlining well interventions.
The play is located within close proximity to markets and has a well-developed infrastructure. Oil and natural gas production is gathered at various production facilities, with the majority of the oil subsequently transported to sales points by pipeline or trucked from facilities depending on the sales contract. Encana has access to firm natural gas gathering capacity of up to approximately 50 MMcf/d and firm processing capacity of up to approximately 80 MMcf/d with third parties under varying terms and duration. During 2018, Encana owned liquids processing capacity increased by 15.0 Mbbls/d with the addition of two new facilities to support Eagle Ford’s growth profile. Encana also utilizes interruptible capacity arrangements for excess production.
Permian
Permian is a tight oil play located in west Texas in the Midland, Martin, Howard, Glasscock and Upton counties. The primary focus is on the development of the Spraberry and Wolfcamp formations in the Midland basin, where Encana holds a large position. At December 31, 2018, Encana controlled approximately 115,000 net acres in the play. The properties are characterized by exposure of up to 11 potential producing horizons spanning approximately 4,000 feet of stratigraphy (also referred to as “stacked pay”), an extensive production history and developed infrastructure. In 2018, production averaged approximately 58.8 Mbbls/d of oil, approximately 19.3 Mbbls/d of NGLs and approximately 86 MMcf/d of natural gas.
During 2018, Encana continued to focus on maximizing efficiency improvements at an industrial scale and maximizing resource recovery by accessing layers of the stacked pay simultaneously using the cube development approach. This approach utilizes large multi-well pads, multi-rig spreads and frac spreads running in parallel to optimize cycle times, increase capital efficiency and reduce costs through economies of scale from higher utilization of services and consumable supplies, while minimizing the development or surface footprint. Encana focused on well productivity by optimizing completions designs, precision targeting of the wells drilled, tighter cluster spacing and using cleaner and thinner fluids to maximize fracture complexity. Encana also improved capital efficiency through its centralized water infrastructure, increased use of recycled water and use of in-basin sand. During 2018, Encana drilled 110 horizontal net wells with lateral lengths ranging from approximately 6,500 to 11,100 feet at a measured average total depth of approximately 18,300 feet with well spacing ranging from approximately 500 to 1,000 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change.
Oil and natural gas facilities include field gathering systems, storage batteries, saltwater disposal systems, separation equipment and pumping units. The majority of Encana’s acreage and associated oil production is dedicated to a pipeline gathering agreement, which has a total remaining term of 11 years including optional renewal terms. In the event of pipeline capacity constraints, Encana’s oil production is trucked by a third party. Natural gas is delivered by Encana to the purchaser’s meter and pipeline interconnection point in the field.
15
PROVED RESERVES AND OTHER OIL AND GAS INFORMATION
The process of estimating oil, NGLs and natural gas reserves is complex and requires significant judgment. Encana’s estimates of proved reserves and associated future net cash flows were evaluated and prepared by the Company’s internal qualified reserves evaluators (“QREs”) and are the responsibility of management. As a result, Encana has developed internal policies that prescribe procedures and standards to be followed for preparing, estimating and recording reserves in compliance with SEC definitions and regulations. Encana’s policies assign responsibilities for compliance in booking reserves and require that reserve estimates be made by its QREs. QRE is defined as a registered professional licensed to practice engineering, geology, geophysics and an individual who has a minimum of five years practical experience, with at least three recent years of experience in the evaluation of reserves.
Encana’s Vice-President, Corporate Reserves & Chief Reservoir Engineering and nine other staff (collectively, the “Corporate Reserves Group”) under this individual’s direction, oversee the internal preparation, review and approval of the reserves estimates. The Corporate Reserves Group reports to the Executive Vice-President, Exploration & Business Development and is separate and independent from the preparation of reserves estimates which are within operations who report to Encana’s Executive Vice-President & Chief Operating Officer. The Corporate Reserves Group maintains Encana’s internal policies that prescribe procedures and standards to be followed for preparing, estimating and recording reserves, which includes updating the Company’s reserves manual, and also conducts periodic internal audits of the procedures, records and controls relating to the preparation of reserves estimates. Encana’s QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the review of the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group. The Corporate Reserves Group also oversees the engagement of independent qualified reserves evaluators (“ IQREs”) or independent qualified reserves auditors (“IQRAs”), if any, retained by the Company.
As a member of the Corporate Reserves Group, the Company’s Director, Corporate Reserves reports to Encana’s Vice-President, Corporate Reserves & Chief Reservoir Engineering and is primarily responsible for overseeing the preparation of proved reserves estimates. The Director, Corporate Reserves has a Bachelor of Science with a degree in Petroleum Engineering from the University of Alberta, is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and the Society of Petroleum Evaluation Engineers (Calgary Chapter).
Annually, each play is reviewed in detail by the QREs, the Corporate Reserves Group, the Company’s executive officers and an internal Reserves Review Committee, as appropriate. The Corporate Reserves Group also conducts a separate review to ensure the effectiveness of the disclosure controls and that the reserves estimates are free from material misstatement. The final reserves estimates are reviewed by Encana’s Reserves Committee of the Board of Directors (the “Reserves Committee”), for approval by the Board of Directors. The Reserves Committee comprises directors that are independent and familiar with estimating oil and gas reserves and disclosure requirements. The Reserves Committee provides additional oversight to the Company’s reserves process, meeting with management periodically to review the reserves process, the portfolio of properties results and related disclosures. The Reserves Committee is also responsible for reviewing the qualifications and appointment of IQREs or IQRAs, if any, retained by the Company, including recommending the selection of such IQREs or IQRAs to the Board of Directors for its approval, and will meet with such IQREs or IQRAs to review their reports.
For year-ended December 31, 2018, Encana involved IQRAs to audit and review the processes relating to the Company’s internal oil and gas reserve estimates for certain properties. In 2018, McDaniel & Associates Consultants Ltd. audited 23 percent of Encana’s estimated Canadian proved reserves volumes and Netherland, Sewell & Associates, Inc. audited 54 percent of Encana’s estimated U.S. proved reserves volumes. An audit of reserves is an examination of a company’s oil and gas reserves and future net cash flows by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.
Proved oil and gas reserves are those quantities of oil, gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have
16
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years.
The Company’s reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations . Data used in assessments include information obtained directly from the subsurface through wellbores such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. In the case of producing reserves, the emphasis is on decline analysis where volumetric analysis is considered to limit forecasts to reasonable levels. Non-producing reserves are estimated by analogy to producing offsets, with consideration of volumetric estimates of in place quantities. All locations to which proved undeveloped reserves have been assigned are subject to a development plan adopted by Encana’s management. The tools used to interpret the data included proprietary and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir are based on the unique circumstances of each reservoir and the dataset available at the time of the estimate.
In general, estimates of economically recoverable reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of crude oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies, and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development, and operating expenditures with respect to the reserves associated with the Company's properties may vary from the information presented herein, and such variations could be material.
The SEC regulations require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, Encana’s reserves have been calculated utilizing the 12-month average trailing historical price for each of the years presented prior to the effective date of the report. The 12-month average is calculated as an unweighted average of the first-day-of-the-month price for each month. The reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.
Encana does not file any estimates of total net proved reserves with any U.S. federal authority or agency other than the SEC and the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of the Company’s reserves contained in its reports. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of Encana’s reserves that are filed with the SEC, however, the DOE requires reports to include the interests of all owners in wells that Encana operates and to exclude all interests in wells that Encana does not operate. Encana is also required to provide reserves data prepared in accordance with Canadian securities regulatory requirements, specifically National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) which is filed concurrently on SEDAR at www.sedar.com under Encana’s issuer profile. The primary differences between NI 51-101 reporting requirements and SEC requirements include the disclosure of proved and probable reserves estimated using forecast prices and costs, presentation of reserves and production before royalties and granular product type disclosures. The reserves data prepared in accordance with NI 51-101 do not form part of this Annual Report on Form 10-K.
The reserves and other oil and gas information set forth below has an effective date of December 31, 2018 and was prepared as of January 11, 2019. The audit reports prepared by the IQRAs are attached in Exhibits 99.1 and 99.2 of this Annual Report on Form 10-K.
The following table is a summary of the Company’s proved reserves and estimates of future net cash flows and discounted future net cash flows from proved reserves information relating to proved reserves which can also be found in Note 27 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
17
The table below summarizes the Company’s total proved reserves by oil, NGLs and natural gas and by geographic area as at December 31, 2018 and other summary operating data.
|
|
As at December 31, 2018 |
||||||
|
|
|
Canada |
|
U.S. |
|
Total |
|
|
Proved Reserves: (1) |
|
|
|
|
|
|
|
|
Oil (MMbbls): |
|
|
|
|
|
|
|
|
Developed |
|
0.2 |
|
150.6 |
|
150.9 |
|
|
Undeveloped |
|
- |
|
200.9 |
|
200.9 |
|
|
Total |
|
0.2 |
|
351.5 |
|
351.8 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids (MMbbls): |
|
|
|
|
|
|
|
|
Developed |
|
60.8 |
|
59.4 |
|
120.2 |
|
|
Undeveloped |
|
97.8 |
|
62.8 |
|
160.6 |
|
|
Total |
|
158.5 |
|
122.3 |
|
280.8 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (Bcf): |
|
|
|
|
|
|
|
|
Developed |
|
1,707 |
|
295 |
|
2,002 |
|
|
Undeveloped |
|
1,195 |
|
302 |
|
1,497 |
|
|
Total |
|
2,901 |
|
598 |
|
3,499 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved Reserves (MMBOE): |
|
|
|
|
|
|
|
|
Developed |
|
345.4 |
|
259.3 |
|
604.7 |
|
|
Undeveloped |
|
296.9 |
|
314.1 |
|
611.0 |
|
|
Total |
|
642.3 |
|
573.4 |
|
1,215.7 |
|
|
|
|
|
|
|
|
|
|
|
Percent Proved Developed |
|
54% |
|
45% |
|
50% |
|
|
Percent Proved Undeveloped |
|
46% |
|
55% |
|
50% |
|
|
|
|
|
|
|
|
|
|
|
Production (MBOE/d) |
|
217.5 |
|
143.7 |
|
361.2 |
|
|
Capital Investments (millions) |
|
$632 |
|
$1,332 |
|
$1,964 |
|
|
Total Net Producing Wells (2) |
|
1,863 |
|
2,288 |
|
4,151 |
|
|
Standardized Measure of Discounted Net Cash Flows: (3) |
|
|
|
|
|
||
|
Pre-Tax (millions) |
|
$2,975 |
|
$7,492 |
|
$10,467 |
|
|
Taxes (millions) |
|
321 |
|
542 |
|
863 |
|
|
After-Tax (millions) |
|
$2,654 |
|
$6,950 |
|
$9,604 |
|
|
(1) |
Numbers may not add due to rounding. |
|
(2) |
Total net producing wells includes producing wells and wells mechanically capable of production. |
|
(3) |
The Pre-Tax standardized measure of discounted cash flows (“standardized measure”) is a non-GAAP measure. The Company believes the Pre-Tax standardized measure is a useful measure in addition to the After-Tax standardized measure, as it assists in both the estimation of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The After-Tax standardized measure is dependent on the unique tax situation of each individual company, while the Pre-Tax standardized measure is based on prices and discount factors, which are more consistent between peer companies. See Note 27 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K for the standardized measure. |
18
Changes to the Company’s proved reserves during 201 8 are summarized in the table below:
|
|
2018 |
|||
|
|
Oil (MMbbls) |
NGLs (MMbbls) |
Natural Gas (Bcf) |
Total (MMBOE) |
|
Beginning of year (1) |
192.5 |
182.5 |
2,519 |
794.9 |
|
Revisions and improved recovery (2) |
19.7 |
(3.2) |
285 |
64.1 |
|
Extensions and discoveries |
162.4 |
127.4 |
1,118 |
476.2 |
|
Purchase of reserves in place |
21.3 |
7.7 |
39 |
35.5 |
|
Sale of reserves in place |
(11.4) |
(5.1) |
(40) |
(23.1) |
|
Production |
(32.8) |
(28.5) |
(423) |
(131.9) |
|
End of year |
351.8 |
280.8 |
3,499 |
1,215.7 |
|
Developed |
150.9 |
120.2 |
2,002 |
604.7 |
|
Undeveloped |
200.9 |
160.6 |
1,497 |
611.0 |
|
Total |
351.8 |
280.8 |
3,499 |
1,215.7 |
|
(1) |
Numbers may not add due to rounding. |
|
(2) |
Changes in reserve estimates resulting from application of improved recovery techniques are nil and are included in revisions of previous estimates. |
In 2018, Encana’s proved reserves of 1,215.7 MMBOE increased 420.8 MMBOE from 2017 primarily due to extensions and discoveries of 476.2 MMBOE from successful drilling and delineation of the Permian, Montney, Eagle Ford, and Duvernay. Approximately 61% of the 2018 extensions and discoveries were crude oil, condensate and NGLs. Revisions of previous estimates of 64.1 MMBOE included negative revisions of 79.0 MMBOE due to changes in the approved development plan, more than offset by positive forecast changes other than price of 133.7 MMBOE resulting from well performance and development strategy and higher 12-month average trailing prices of 9.4 MMBOE.
Purchases of 35.5 MMBOE were primarily in the Permian and sales of reserves in place of 23.1 MMBOE were primarily associated with the divestiture of San Juan. Production for 2018 was 131.9 MMBOE.
Proved reserves are estimated based on the average beginning-of-month prices during the 12-month period for the respective year. The average prices used to compute proved reserves at December 31, 2018 were WTI: $ 65.56 per bbl, Edmonton Condensate: C$ 79.59 per bbl, Henry Hub: $3.10 per MMBtu, and AECO: C$ 1.49 per MMBtu. Prices for natural gas, oil and NGLs can fluctuate widely.
Proved Undeveloped Reserves
Changes to the Company’s proved undeveloped reserves during 2018 are summarized in the table below:
|
( MMBOE) |
2018 |
|
Beginning of year |
387.1 |
|
Revisions of prior estimates |
(52.2) |
|
Extensions and discoveries |
404.2 |
|
Conversions to developed |
(153.8) |
|
Purchase of reserves in place |
33.9 |
|
Sale of reserves in place |
(8.1) |
|
End of Year |
611.0 |
* Numbers may not add due to rounding.
As of December 31, 2018, there were no proved undeveloped reserves that will remain undeveloped for five years or more.
Extensions and discoveries of 404.2 MMBOE of proved undeveloped reserves were the result of successful drilling and delineation in the Permian, Montney, and Eagle Ford. Revisions of previous estimates of proved undeveloped reserves were revised down by 52.2 MMBOE primarily due to the removal of proved undeveloped locations of 79.0 MMBOE resulting from changes in the development plan related to Montney, Permian, Eagle Ford, and Duvernay, where specific locations previously planned to be drilled within five years were shifted to a later development timeframe or removed and replaced with different locations that are included in extensions and discoveries. In
19
addition, revisions of previous estimates included a positive revision of 24.3 MMBOE from increased well performance .
Conversions of proved undeveloped reserves to proved developed status were 153.8 MMBOE, equating to 40 percent of the total prior year-end proved undeveloped reserves. Approximately 69 percent of proved undeveloped reserves conversions occurred in Canada in Montney and Duvernay and 31 percent occurred in the U.S. in Permian and Eagle Ford. Encana spent approximately $ 929 million to develop proved undeveloped reserves in 2018, of which approximately 38 percent related to the Canadian properties and 62 percent related to the U.S. properties.
Purchases of proved undeveloped reserves of 33.9 MMBOE relate to acquisitions in the Permian and Eagle Ford. Sales of proved undeveloped reserves of 8.1 MMBOE relate primarily to the disposition of San Juan.
Sales Volumes, Prices and Production Costs
The following table summarizes the Company’s production by final product sold, average sales price, and production cost per BOE for each of the last three years by geographic area:
20
Drilling and other exploratory and development activities (1, 2)
The following tables summarize Encana’s gross participation and net interest in wells drilled for the periods indicated by geographic area.
Drilling and other exploratory and development activities (1, 2)
The following table summarizes the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion by geographic area at December 31, 2018.
Oil and gas properties, wells, operations, and acreage
The following table summarizes the number of producing wells and wells mechanically capable of production by geographic area at December 31, 2018.
|
(1) |
“Gross” wells are the total number of wells in which Encana has an interest. |
|
(2) |
“Net” wells are the number of wells obtained by aggregating Encana’s working interest in each of its gross wells. |
|
(3) |
Includes 58 gross oil wells (34 net oil wells) containing multiple completions. |
|
(4) |
Includes 1,991 gross natural gas wells (1,592 net natural gas wells) containing multiple completions. |
21
The following table summarizes Encana’s developed, undeveloped and total landholdings by geographic area as at December 31, 201 8 .
Of the total 2.0 million net acres, approximately 0.7 million net acres is held by production. The table above includes acreage subject to leases that will expire over the next three years: 2019 – approximately 193,000 net acres; 2020 – approximately 134,000 net acres; and 2021 – approximately 141,000 net acres, if the Company does not establish production or take any other action to extend the terms. For acreage that the Company intends to further develop, Encana will perform operational and administrative actions to continue the lease terms that are set to expire. As a result, it is not expected that a significant portion of the Company’s net acreage will expire before such actions occur.
Title to Properties
As is customary in the oil and natural gas industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time Encana acquires properties. The Company believes that title to all of the various interests set forth in the above table is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in Encana’s operations. The interests owned by Encana may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Company’s operations.
22
Market Optimization activities are managed by Encana’s Midstream, Marketing & Fundamentals team, which is responsible for the sale of the Company’s proprietary production and enhancing the associated netback price. In marketing production, Encana looks to minimize market related shut-ins, maximize realized prices and manage concentration of credit-risk exposure. Market Optimization activities include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. In conjunction with certain divestitures, Encana has also agreed to market and transport certain portions of the acquirer’s production with remaining terms of less than three years.
Encana’s produced oil, NGLs and natural gas, are primarily marketed to refiners, local distributing companies, energy marketing companies and electronic exchanges. Prices received by Encana are based primarily upon prevailing market index prices in the region in which it is sold . Prices are impacted by regional and global supply and demand and by competing fuels in such markets.
Encana’s oil production is sold under short term and evergreen contracts, long term contracts or under dedication agreements, for which prices received by Encana are based primarily upon the prevailing index prices in the relevant region where the product is sold. Encana’s NGLs production is sold under short term and long-term contracts that range up to 10 years, or under dedication arrangements at the relevant market price at the time the product is sold. Encana's natural gas production is sold under short-term delivery contracts with terms less than two years in duration, at the relevant monthly or daily market price at the time the product is sold. The Company also has firm transport contracts to deliver natural gas production to other downstream markets, including Dawn.
Encana also seeks to mitigate the market risk associated with future cash flows by entering into various financial derivative instruments used to manage price risk relating to produced oil, NGLs and natural gas. Details of contracts related to Encana’s various financial risk management positions are found in Note 23 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
The Company enters into various contractual agreements to sell oil, NGLs and natural gas, some of which require the delivery of fixed and determinable quantities. As of December 31, 2018, Encana was committed to deliver approximately 7,700 Mbbls of oil and NGLs and approximately 121,800 MMcf of natural gas in the Canadian Operations and approximately 37,000 Mbbls of oil and approximately 58,600 MMcf of natural gas in the USA Operations with varying contract terms up to 5 years.
Certain transportation and processing commitments result in the following financial commitments:
In general, Encana expects to fulfill delivery commitments with production from proved developed reserves, with longer term delivery commitments to be filled from the Company’s proved undeveloped reserves. Where proved reserves are not sufficient to satisfy the Company’s delivery commitments, Encana can and may use spot market purchases to satisfy the respective commitments. In addition, for the Company’s long-term transportation and processing agreements, Encana also expects to fulfill delivery commitments from the future development of resources not yet characterized as proved reserves. Likewise, where delivery commitments are not transferred along with property divestitures, Encana may market and transport certain portions of the acquirer’s production to meet the delivery requirements.
23
In addition, production from the Company’s reserves are not subject to any priorities or curtailments that may affect quantities delivered to its customers or any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company’s control that may affect Encana’s ability to meet contractual obligations other than those discussed in Item 1A. Risk Factors of this Annual Report on Form 10-K.
MAJOR CUSTOMERS
In connection with the marketing and sale of Encana’s production and purchased oil, NGLs and natural gas for the year ended December 31, 2018, the Company had one customer, Royal Dutch Shell, which individually accounted for more than 10 percent of Encana’s consolidated revenues (2017 and 2016 – two customers, Royal Dutch Shell Group and Flint Hills Resources). Encana does not believe that the loss of any single customer would have a material adverse effect on the Company’s financial condition or results of operations. Further information on Encana’s major customers are found in Note 2 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
COMPETITION
The Company’s competitors include national, integrated and independent oil and gas companies, as well as oil and gas marketers and other participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. All aspects of the oil and gas industry are highly competitive and Encana actively competes with other companies in the industry, particularly in the following areas:
• Exploration for and development of new sources of oil, NGLs and natural gas reserves;
• Reserves and property acquisitions;
• Transportation and marketing of oil, NGLs, natural gas and diluents;
• Access to services and equipment to carry out exploration, development and operating activities; and
• Attracting and retaining experienced industry personnel.
The oil and gas industry also competes with other industries focused on providing alternative forms of energy to consumers. Competitive forces can lead to cost increases or result in an oversupply of oil, NGLs or natural gas.
At December 31, 2018, Encana employed 2,065 employees as set forth in the following table.
|
|
Employees |
|
Canada |
1,133 |
|
U.S. |
932 |
|
Total |
2,065 |
The Company also engages a number of contractors and service providers.
ENVIRONMENTAL AND REGULATORY MATTERS
As Encana is an owner or lessee and operator of oil and gas properties and facilities in Canada and the United States, the Company is subject to numerous federal, provincial, state, local, tribal and foreign country laws and regulations relating to pollution, protection of the environment and the handling of hazardous materials. These laws and regulations generally require Encana to remove or remedy the effect of its activities on the environment at present and former operating sites, including dismantling production facilities, remediating damage caused by the use or release of specified substances, and require suspension or cessation of operations in affected areas. The following are significant areas of government control and regulation affecting Encana’s operations:
Exploration and Development Activities
Our operations are subject to federal, tribal, state, provincial and local laws and regulations. These laws and regulations relate to matters that include: acquisition of seismic data; location, drilling and casing of wells; well design; hydraulic fracturing; well production; use, transportation, storage and disposal of fluids and materials
24
incidental to oil and gas operations; surface usage and the restoration of properties upon which wells have been drilled and facilities have been constructed; plugging and abandoning of wells; transportation of production; and calculation and disbursement of royalty payments and production and other taxes.
The Company’s operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In addition, conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas that can be produced from the Company’s wells and the number of wells or the locations that can be drilled.
Environmental and Occupational Regulations
The Company is subject to many federal, state, provincial, local and tribal laws and regulations concerning occupational health and safety as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to:
• the discharge of pollutants into federal, provincial and state waters;
• assessing the environmental impact of seismic acquisition, drilling or construction activities;
• the generation, storage, transportation and disposal of waste materials, including hazardous substances;
• the emission of certain gases into the atmosphere;
• the sourcing and disposal of water;
• the protection of endangered species and habitat;
|
|
|
• the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; |
• the development of emergency response and spill contingency plans; and
• employee health and safety.
Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Although environmental requirements have a substantial impact upon the energy industry as a whole, Encana does not believe that these requirements affect the Company differently, to any material degree, as compared to other companies in the oil and natural gas industry. For further information regarding regulations relating to environmental protection, see Item 1A. Risk Factors of this Annual Report on Form 10-K.
Operating and capital costs incurred to comply with the requirements of these laws and regulations are necessary business costs in the oil and gas industry. As a result, Encana has established policies for continuing compliance with environmental laws and regulations. The Corporate Responsibility, Environment, Health and Safety Committee of the Board of Directors reviews and recommends environmental policy to the Board of Directors for approval and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. The Company has established operating procedures and training programs designed to limit the environmental impact of the Company’s field facilities and identify, communicate and comply with changes in existing laws and regulations. Contingency plans are in place for a timely response to an environmental event and remediation/reclamation programs are in place and utilized to restore the environment. In addition, the Board of Directors is advised of significant contraventions thereof, and receives updates on trends, issues or events which could have a significant impact on the Company.
The Company believes that it is in material compliance with existing environmental and occupational health and safety regulations. Further, the Company believes that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on its business, financial condition or results of operations. In addition, Encana maintains insurance coverage for insurable risks against certain environmental and occupational health and safety risks that is consistent with insurance coverage held by other similarly situated industry participants, but the Company is not fully insured against all such risks . However, it is possible that developments, such as new or more stringently applied existing laws and regulations as well as claims for damages to property or
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persons resulting from the Company’s operations, could result in substantial costs and liabilities to the Company. As a result, Encana is unable to predict with any reasonable degree of certainty future exposures concerning such matters.
EXECUTIVE OFFICERS OF THE REGISTRANT
Encana’s Executive Officers are set out in the table below:
|
Name |
Age (1) |
Years Served as Executive Officer |
Corporate Office |
|
|
|
|
|
|
Douglas J. Suttles |
58 |
6 |
President & Chief Executive Officer |
|
Joanne L. Alexander
|
52 |
4 |
Executive Vice-President & General Counsel |
|
Sherri A. Brillon
|
59 |
12 |
Executive Vice-President & Chief Financial Officer |
|
David G. Hill
|
57 |
5 |
Executive Vice-President, Exploration & Business Development |
|
Michael G. McAllister
|
60 |
8 |
Executive Vice-President & Chief Operating Officer |
|
Michael Williams
|
59 |
5 |
Executive Vice-President, Corporate Services |
|
Renee E. Zemljak
|
54 |
9 |
Executive Vice-President, Midstream, Marketing & Fundamentals |
|
|
(1) |
As of February 28, 2019 |
Mr. Suttles was appointed President & Chief Executive Officer in June 2013. Prior to that, Mr. Suttles was an independent businessman performing consulting services in the oil and gas industry and serving on the boards of one public and one private company from March 2011 until June 2013. Mr. Suttles was also Chief Operating Officer at BP Exploration & Production from January 2009 until March 2011.
Ms. Alexander was appointed Executive Vice-President & General Counsel on January 2015. Prior to that, Ms. Alexander was Senior Vice President, General Counsel and Corporate Secretary of Precision Drilling Corporation (a public oil and gas services company) from April 2008 to December 2014 and General Counsel of Marathon Oil Canada Corporation (an oil and gas company) from 2007 to 2008.
Ms. Brillon was appointed Executive Vice-President & Chief Financial Officer in November 2009. Ms. Brillon joined one of Encana’s predecessor companies in 1985 and assumed a variety of leadership roles, including her previous position as Executive Vice-President, Strategic Planning and Portfolio Management in January 2007. Ms. Brillon served as a director of the Canadian Chamber of Commerce (a not-for-profit company) from 2007 to 2009, as a director of PrairieSky Royalty Ltd. (a public oil and gas royalty company) from April 2014 to September 2014 and as a director of Tim Horton’s Inc. (a public restaurant company) from November 2013 to December 2014 . Ms. Brillon currently sits as a member of the Listed Company Advisory Board for the NYSE.
Mr. Hill was appointed Executive Vice-President, Exploration & Business Development in November 2013. Mr. Hill joined Encana in November 2002 and assumed a variety of leadership roles, including his previous position as Vice-President, Natural Gas Economy Operations. Prior to these positions, Mr. Hill was President of TICORA Geosciences (a privately held geosciences company) from 2000 to 2002.
Mr. McAllister was appointed Executive Vice-President & Chief Operating Officer in November 2013. Mr. McAllister joined one of Encana’s predecessor companies in June 2000 and assumed a variety of leadership roles, including his previous position as Executive Vice-President & Senior Vice-President, Canadian Division in February 2011. Before joining Encana, Mr. McAllister worked in various technical and leadership roles for Texaco Canada and Imperial Oil Resources.
Mr. Williams was appointed Executive Vice-President , Corporate Services in March 2014. Prior to that, Mr. Williams was Executive Vice-President of Corporate Services with Tervita Corporation (a private energy services company) from 2011 to 2014 and Chief Administration Officer for TransAlta Corporation (a public power company) from 2002 to 2011.
Ms. Zemljak was appointed Executive Vice-President, Midstream, Marketing & Fundamentals in November 2009. Ms. Zemljak joined one of Encana’s predecessor companies in November 2000 and assumed a variety of leadership
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roles, including her previous position as Vice-President of USA Marketing in May 2002. Prior to joining Encana, Ms. Zemljak worked in various roles for Montana Power (formerly a public power company) .
If any event arising from the risk factors set forth below occurs, Encana’s business, prospects, financial condition, results of operations, cash flows or the trading prices of securities and in some cases its reputation could be materially adversely affected. When assessing the materiality of the foregoing risk factors, Encana takes into account a number of qualitative and quantitative factors, including, but not limited to, financial, operational, environmental, regulatory, reputational and safety aspects of the identified risk factor.
A substantial or extended decline in natural gas, oil or NGLs prices and price differentials could have a material adverse effect on Encana’s financial condition.
Encana’s financial performance and condition are substantially dependent on the prevailing prices of natural gas, oil and NGLs. Low natural gas, oil or NGLs prices and significant U.S. and Canadian price differentials will have an adverse effect on the Company’s operations and financial condition and the value and amount of its reserves. Prices for natural gas, oil or NGLs fluctuate in response to changes in the supply and demand for natural gas, oil or NGLs, market uncertainty and a variety of additional factors beyond the Company’s control.
Natural gas prices realized by Encana are affected primarily by North American supply and demand, weather conditions, transportation and infrastructure constraints, prices and availability of alternate sources of energy (including refined products, coal, and renewable energy initiatives) and by technological advances affecting energy consumption. Oil prices are largely determined by international and domestic supply and demand. Factors which affect oil prices include the actions of the OPEC, world economic conditions, government regulation, political stability in the Middle East and elsewhere, the foreign and domestic supply of oil, the price of foreign imports, the availability of alternate fuel sources, transportation and infrastructure constraints and weather conditions. Historically, NGLs prices have generally been correlated with oil prices, and are determined based on supply and demand in international and domestic NGLs markets.
A substantial or extended decline in the price of natural gas, oil or NGLs could result in a delay or cancellation of existing or future drilling, development or construction programs or curtailment or shut-in of production at some properties or could result in unutilized long-term transportation and drilling commitments, all of which could have an adverse effect on the Company’s revenues, profitability and cash flows.
Natural gas and oil producers in North America, and particularly in Canada, currently receive discounted prices for their production relative to certain international prices due to constraints on their ability to transport and sell such production to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by natural gas and oil producers, including Encana.
On at least an annual basis, Encana conducts an assessment of the carrying value of its assets in accordance with the applicable accounting standards. If natural gas, oil or NGLs prices decline further, the carrying value of Encana’s assets could be subject to financial downward revisions, and the Company’s net earnings could be adversely affected.
Encana’s ability to operate and complete projects is dependent on factors outside of its control which may have a material adverse effect on its business, financial condition or results of operations.
The Company’s ability to operate, generate sufficient cash flows, and complete projects depends upon numerous factors beyond the Company’s control. In addition to commodity prices and continued market demand for its products, these non-controllable factors include general business and market conditions, economic recessions and financial market turmoil, the overall state of the capital markets, including investor appetite for investments in the oil and gas industry generally and the Company’s securities in particular, the ability to secure and maintain cost effective financing for its commitments, legislative, environmental and regulatory matters, changes to free trade agreements, reliance on industry partners and service providers, unexpected cost increases, royalties, taxes, including the impact of recent U.S. tax reform and potential U.S. Treasury Department regulations and guidance, volatility in natural gas, oil or NGLs prices, the availability of drilling and other equipment, the ability to access
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lands, the ability to access water for hydraulic fracturing operations, physical impacts from adverse weather conditions and other natural disasters, the availability and proximity of processing and pipeline capacity, transportation interruptions and constraints, technology failures, accidents, the availability of skilled labour and reservoir quality. In addition, some of these risks may be magnified due to the concentrated nature of funding certain assets within the Company’s portfolio of oil and natural gas properties that are operated within limited geographic areas. As a result, a number of the Company’s assets could experience any of the same risks and conditions at the same time, resulting in a relatively greater impact on the Company’s financial condition and results of operations compared to other companies that may have a more geographically diversified portfolio of properties.
Fluctuations in natural gas, oil or NGLs prices can create fiscal challenges for the oil and gas industry. These conditions have impacted companies in the oil and gas industry and the Company’s spending and operating plans and may continue to do so in the future. There may be unexpected business impacts from market uncertainty, including volatile changes in currency exchange rates, inflation, interest rates, defaults of suppliers and general levels of investing and consuming activity, as well as a potential impact on the Company’s credit ratings, which could affect its liquidity and ability to obtain financing.
The Company undertakes a variety of projects including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may delay expected revenues and project cost overruns could make projects uneconomic.
All of Encana’s operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact the Company’s existing and planned projects.
Encana’s proved reserves are estimates and any material inaccuracies in our reserves estimates or assumptions underlying our reserves estimates could cause quantities and net present value of our reserves to be overstated or understated.
There are numerous uncertainties inherent in estimating quantities of natural gas, oil and NGLs reserves, including many factors beyond the Company’s control. The reserves data in this Annual Report on Form 10-K and other published reserves and resources data represents estimates only. In general, estimates of economically recoverable natural gas, oil and NGLs reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as commodity prices, future operating and capital costs, availability of future capital, historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain, and classifications of reserves and resources are only attempts to define the degree of uncertainty involved.
For those reasons, estimates of the economically recoverable natural gas, oil and NGLs reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Encana’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material. Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.
The estimates of reserves included in this Annual Report on Form 10-K are prepared in accordance with SEC regulations and require, subject to limited exceptions, that proved undeveloped reserves may only be classified as proved reserves if the related wells are scheduled to be drilled within five years after the date of booking. Reserves to be developed and produced in the future are based upon certain expectations and assumptions, including the allocation of capital, which may be subject to change. Proved undeveloped reserves may be reclassified to unproved due to delays in the development of reserves, or projects becoming uneconomical due to increases in costs to drill such reserves, or lower future net revenues from further decreases in commodity prices.
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Commodity prices used to estimate reserves included in this Annual Report on Form 10-K are calculated as the average oil and natural gas price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. Significant future price changes can have a material effect on the quantity and value of the Company's proved reserves. The standardized measure of discounted future net cash flows included in this Annual Report on Form 10-K will not represent the current market value of Encana’s estimated reserves. In addition, these reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.
If Encana fails to acquire or find additional reserves, the Company’s reserves and production will decline materially from their current levels.
Encana’s future oil, NGLs and natural gas reserves and production, and therefore its cash flows, are highly dependent upon its success in developing its current reserves base and acquiring, discovering or developing additional reserves. Without reserves additions through exploration, acquisition or development activities, the Company’s reserves and production will decline over time as reserves are depleted.
The business of exploring for, developing or acquiring reserves is capital intensive. In addition, part of Encana’s strategy is focused on a limited number of core assets which results in a concentration of capital and increased potential risks. To the extent that cash flows from the Company’s operations are insufficient and external sources of capital become limited, Encana’s ability to make the necessary capital investments to maintain and expand its natural gas, oil and NGLs reserves and production will be impaired. In addition, there can be no certainty that Encana will be able to find and develop or acquire additional reserves to replace production at acceptable costs.
In addition, Encana’s operations utilize horizontal multi-pad drilling, tighter drill spacing and completions techniques that evolve over time as learnings are captured and applied. The use of this technology may increase the risk of unintentional communication with other wells and the potential for acceleration of current reserves or an increase in recovery factor from the reservoir. If drilling and completions results are less than anticipated, the production volumes may be lower than anticipated.
Encana may not realize anticipated benefits from acquisitions.
Encana has completed a number of acquisitions to strengthen its position and to create the opportunity to realize certain benefits, including, among other things, potential cost savings. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations. Acquisitions could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate such properties.
With respect to the Newfield acquisition, there can be no assurance that Encana will be able to successfully integrate Newfield’s assets or otherwise realize the expected benefits of the transaction. Difficulties in integrating Newfield into Encana may result in the combined company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties that may be encountered in the integration process include, among other factors: difficulties integrating the businesses of Newfield and Encana in a manner that permits Encana to achieve the full revenue and cost savings anticipated from the transaction; complexities associated with managing a larger and more complex business; difficulties realizing anticipated operating synergies; difficulties integrating personnel, vendors and business partners; loss of key employees; potential unknown liabilities and unforeseen expenses, delays or regulatory conditions; performance shortfalls at one or both of the companies as a result of the diversion of management’s attention to integration efforts; inconsistencies between each company’s standards, controls, policies and procedures; and the disruption of, or the loss of momentum in, each company’s ongoing business.
Encana has also incurred, and is expected to continue to incur, a number of costs associated with completing the Newfield acquisition and combining the businesses of Newfield and Encana. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the two companies, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all.
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Encana’s future success will depend, in part, on its ability to manage its expanded business by, among other things, integrating the assets, operations and personnel of Newfield and Encana in an efficient and timely manner; consolidating systems and management controls; and successfully integrating relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on Encana’s business, reputation, financial condition and results of operations.
Encana may be subject to additional risks from acquisitions.
Acquiring oil and natural gas properties requires the Company to assess reservoir and infrastructure characteristics, including estimated recoverable reserves, future production, commodity prices, revenues, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain and, as such, the acquired properties may not produce as expected, may not have the anticipated reserves and may be subject to increased costs and liabilities.
Although the acquired properties are reviewed prior to completion of an acquisition, such reviews are not capable of identifying all existing or potentially adverse conditions. This risk may be magnified where the acquired properties are in geographic areas where the Company has not historically operated. Further, the Company may not be able to obtain or realize upon contractual indemnities from the seller for liabilities created prior to an acquisition and it may be required to assume the risk of the physical condition of the properties that may not perform in accordance with its expectations.
As a result of the Newfield acquisition, Encana may also be exposed to additional risks or unknown or undisclosed liabilities to which it has not historically been exposed. Encana’s management may not be able to anticipate or effectively manage these additional risks, which could adversely impact Encana’s business, financial condition and results of operations.
The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and any changes in such regulation could negatively affect its results of operations.
All phases of the natural gas, oil and NGLs businesses are subject to environmental regulation pursuant to a variety of Canadian, U.S. and other federal, provincial, territorial, tribal, state and municipal laws and regulations (collectively, “environmental regulation”).
Environmental regulation imposes, among other things, restrictions, liabilities and obligations in connection with the use, generation, handling, storage, transportation, treatment and disposal of chemicals, hazardous substances and waste associated with the finding, production, transmission and storage of the Company’s products including the hydraulic fracturing of wells, the decommissioning of facilities and in connection with spills, releases and emissions of various substances to the environment. It also imposes restrictions, liabilities and obligations in connection with the availability and management of fresh, potable or brackish water sources that are being used, or whose use is contemplated, in connection with natural gas and oil operations.
Environmental regulation also requires that wells, facility sites and other properties associated with Encana’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Compliance with environmental regulation can require significant expenditures, including expenditures for clean-up costs and damages arising out of contaminated properties and failure to comply with environmental regulation may result in the imposition of fines and penalties.
Although it is not expected that the costs of complying with environmental regulation will have a material adverse effect on Encana’s financial condition or results of operations, no assurance can be made that the costs of complying with environmental regulation in the future will not have such an effect as discussed below.
Climate Change - A number of federal, provincial and state governments have announced intentions to regulate greenhouse gases and certain air pollutants. These governments are currently developing regulatory and policy frameworks to deliver on their announcements. The Canadian federal government along with certain provinces and territories, including Alberta and British Columbia, have announced a pan-Canadian climate change framework that
30
is consistent with the outcome reached at the 21 st Conference of the Parties in Paris and which includes imposing an economy wide cost on carbon emissions in Canada by 2023. The Alberta government outlined its Climate Leadership Plan which includes four key areas, one of which is targeting a 45 percent reduction in methane gas emissions from oil and gas operations by 2025, to be achieved through equipment replacement and leak detection and repair regulations. Both Alberta and British Columbia have implemented a provincial carbon tax; Alberta introduced a carbon levy in January 2017 of C$20 per tonne of CO 2 e, which increased to C$30 per tonne of CO 2 e in 2018 while British Columbia has an established carbon levy of C$30 per tonne of CO 2 e, increasing by C$5 per tonne of CO 2 e per year starting April 1, 2018 until it reaches C$50 per tonne of CO 2 e in 2021 . In October of 2018 , the U nited S tates Environmental Protection Agency (“EPA”) issued a reconsideration reforming the rules that regulate methane emissions from the oil and gas industry. Public comment on the proposed revised regulations closed in December 2018 and the new regulations are expected to be finalized in 2019. Encana’s cost of complying with emerging climate and cost of carbon regulations is not currently forecast to be material to the Company, however as these and additional federal and regional programs are in their early implementation stage or under development, Encana is unable to predict the total future impact of the potential regulations upon its business. Therefore, it is possible that the Company could face future increases in operating costs in order to comply with legislation governing emissions. Further, certain local governments, stakeholders and other groups have made claims against companies in the oil and gas industry, including the Company, relating to the purported causes and impact of climate change. These claims have, among other things, resulted in litigation, shareholder proposals and local ballot initiatives targeted against certain companies and the oil and gas industry generally. As these claims are in their early stages, the Company is unable to assess the impact of such claims on its business, but the defense of such matters may be costly and time consuming and could have a material adverse effect on the Company’s reputation.
Hydraulic Fracturing - The U.S. and Canadian federal governments and certain U.S. state and Canadian provincial governments continue to review certain aspects of the scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. Most of these governments are primarily engaged in the collection, review and assessment of technical information regarding the hydraulic fracturing process and have not provided specific details with respect to any significant actual, proposed or contemplated changes to the hydraulic fracturing regulatory construct. However, certain environmental and other groups continue to suggest that additional federal, provincial, territorial, state and municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process, and have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources.
Further, certain governments in jurisdictions where the Company does not currently operate have considered or implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments have adopted, and others have considered adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs or third party or governmental claims, and could increase the Company’s cost of compliance and doing business as well as reduce the amount of natural gas and oil that the Company is ultimately able to produce from its reserves. The Company recognizes that additional hydraulic fracturing ballot initiatives and/or local rule-making limiting or restricting oil and gas development activities are a possibility in the future.
As these federal and regional programs are in their early implementation stage or under development, Encana is unable to predict the total impact of the potential regulations upon its business. Therefore, it is possible that the Company could face increases in operating costs or curtailment of production in order to comply with legislation governing hydraulic fracturing.
Seismic Activity – Some areas of North America are experiencing increasing localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence and risk of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater and has been correlated with hydraulic fracturing activities which has prompted legislative and regulatory initiatives intended to address these concerns. These initiatives have the potential to require additional monitoring, restrict the injection of produced water in certain disposal wells and/or modify or curtail hydraulic fracturing operations which could lead to operational delays, increase compliance costs or otherwise adversely impact the Company’s operations.
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Encana’s risk management activities may prevent the Company from fully benefiting from price increases and expose us to other risks.
The nature of the Company’s operations results in exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company monitors its exposure to such fluctuations and, where the Company deems it appropriate, utilizes derivative financial instruments and physical delivery contracts to mitigate the potential impact of declines in natural gas, oil or NGLs prices and fluctuations in foreign currency exchange rates.
Under U.S. GAAP, derivative financial instruments that do not qualify or are not designated as hedges for accounting purposes are fair valued with the resulting changes recognized in current period net earnings. The utilization of derivative financial instruments may therefore introduce significant volatility into the Company’s reported net earnings.
The terms of the Company’s various risk management agreements and the amount of estimated production hedged may limit the benefit to the Company of commodity price increases. The Company may also suffer financial loss if the Company is unable to produce natural gas, oil or NGLs, or if counterparties to the Company’s risk management agreements fail to fulfill their obligations under the agreements, particularly during periods of declining commodity prices.
Downgrades in Encana’s credit ratings could increase its cost of capital and limit its access to capital, suppliers or counterparties.
Rating agencies regularly evaluate the Company, basing their ratings of its long-term and short-term debt on a number of factors. This includes the Company’s financial strength as well as factors not entirely within its control, including conditions affecting the oil and gas industry generally and the wider state of the economy. One of the Company’s credit ratings is below an investment-grade credit rating. There can be no assurance that the Company’s other credit ratings will not also be downgraded, including below an investment-grade credit rating.
The Company’s borrowing costs and ability to raise funds are directly impacted by its credit ratings. A downgrade may increase the cost of borrowing under the Company’s existing credit facilities, limit access to private and public markets to raise short-term and long-term debt, and negatively impact the Company’s cost of capital. Further, as a result of one of the Company’s credit ratings being below investment grade, access to the Company’s U.S. commercial paper program has been eliminated.
Credit ratings may also be important to suppliers or counterparties when they seek to engage in certain transactions. Downgrades in one or more of the Company’s credit ratings below investment-grade may require the Company to post collateral, letters of credit, cash or other forms of security as financial assurance of the Company’s performance under certain contractual arrangements with marketing counterparties, facility construction contracts, and pipeline and midstream service providers. Additionally, certain of these arrangements contain financial assurance language that may, under certain circumstances, permit the Company’s counterparties to request additional collateral.
In connection with certain over-the-counter derivatives contracts and other trading agreements, the Company could be required to provide additional collateral or to terminate transactions with certain counterparties based on its credit rating. The occurrence of any of the foregoing could adversely affect the Company’s ability to execute portions of its business strategy, including hedging, and could have a material adverse effect on its liquidity and capital position.
The Company’s level of indebtedness may limit its financial flexibility.
As at December 31, 2018, the Company had total long-term debt of $4,198 million and no outstanding balance under its revolving credit facilities. The terms of the Company’s various financing arrangements, including but not limited to the indentures relating to its outstanding senior notes and its revolving credit facilities, impose restrictions on its ability and, in some cases, the ability of the Company’s subsidiaries, to take a number of actions that it or they may otherwise desire to take, including: (i) incurring additional debt, including guarantees of indebtedness; (ii) creating liens on the Company’s or its subsidiaries’ assets; and (iii) selling certain of the Company’s or its subsidiaries’ assets.
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The Company’s level of indebtedness could affect its operations by:
|
|
• |
requiring it to dedicate a portion of cash flows from operations to service its indebtedness, thereby reducing the availability of cash flow for other purposes; |
|
|
• |
reducing its competitiveness compared to similar companies that have less debt; |
|
|
• |
limiting its ability to obtain additional future financing for working capital, capital investments and acquisitions; |
|
|
• |
limiting its flexibility in planning for, or reacting to, changes in its business and industry; and |
|
|
• |
increasing its vulnerability to general adverse economic and industry conditions. |
The Company’s ability to meet its debt obligations and service those debt obligations depends on future performance. General economic conditions, natural gas, oil or NGLs prices, and financial, business and other factors affect the Company’s operations and future performance. Many of these factors are beyond the Company’s control. If the Company is unable to satisfy its obligations with cash on hand, the Company could attempt to refinance debt or repay debt with proceeds from a public offering of securities or selling certain assets. No assurance can be given that the Company will be able to generate sufficient cash flow to pay the interest obligations on its debt, or that funds from future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance its debt, or on terms that will be favourable to the Company. Further, future acquisitions may decrease the Company’s liquidity by using a significant portion of its available cash or borrowing capacity to finance such acquisitions, and such acquisitions could result in a significant increase in the Company’s interest expense or financial leverage if it incurs additional debt to finance such acquisitions.
Encana’s operations are subject to the risk of business interruption, property and casualty losses. The Company’s insurance may not fully protect us against these risks and liabilities.
The Company’s business is subject to the operating risks normally associated with the exploration for, development of and production of natural gas, oil and NGLs and the operation of midstream facilities. These risks include blowouts, explosions, fire, gaseous leaks, migration of harmful substances and liquid spills, loss of well control, surface spills and uncontrolled ground releases of fluids during hydraulic fracturing or other similar activities, and acts of vandalism and terrorism, any of which could cause personal injury, result in damage to, or destruction of, natural gas and oil wells or formations or production facilities and other property, equipment and the environment, as well as interrupt operations.
In addition, all of Encana’s operations will be subject to all of the risks normally incident to the transportation, processing, storing and marketing of natural gas, oil, NGLs and other related products, drilling and completion of natural gas and oil wells, and the operation and development of natural gas and oil properties, including encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of natural gas, oil or well fluids, adverse weather conditions and other natural disasters, spills and migration of hazardous chemicals, pollution and other environmental risks.
We maintain insurance against some, but not all, of these risks and losses. The occurrence of a significant event against which Encana is not fully insured could have a material adverse effect on the Company’s financial position.
Encana is dependent on partners to fund development projects conducted through joint ventures and partnerships, which if such funding is unavailable may adversely affect the Company’s operations and financial condition.
Some of Encana's projects are conducted through joint ventures, partnerships or other arrangements, where Encana is dependent on its partners to fund their contractual share of the capital and operating expenditures related to such projects. If these partners do not approve or are unable to fund their contractual share of certain capital or operating expenditures, suspend or terminate such arrangements or otherwise fulfill their obligations, this may result in project delays or additional future costs to Encana, all of which may affect the viability of such projects.
These partners may also have strategic plans, objectives and interests that do not coincide with and may conflict with those of Encana. While certain operational decisions may be made solely at the discretion of Encana in its capacity as operator of certain projects, major capital and strategic decisions affecting such projects may require
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agreement among the partners. While Encana and its partners generally seek consensus with respect to major decisions concerning the direction and operation of the project assets, no assurance can be provided that the future demands or expectations of any party, including Encana, relating to such assets will be met satisfactorily or in a timely manner. Failure to satisfactorily meet such demands or expectations may affect Encana's or its partners’ participation in the operation of such assets or the timing for undertaking various activities, which could negatively affect Encana’s operations and financial results. Further, Encana is involved from time to time in disputes with its partners and, as such, it may be unable to dispose of assets or interests in certain arrangements if such disputes cannot be resolved in a satisfactory or timely manner.
The Company may be unable to dispose of certain assets and may be required to retain liabilities for certain matters.
The Company may identify certain assets for disposition, which could increase capital available for other activities or reduce the Company’s existing indebtedness. Various factors could materially affect the Company’s ability to dispose of those assets or complete announced transactions, including current commodity prices, the availability of purchasers willing to purchase certain assets at prices and on terms acceptable to the Company, approval by the Board of Directors, associated asset retirement obligations, due diligence, favourable market conditions, the assignability of joint venture, partnership or other arrangements and stock exchange, regulatory and third party approvals. These factors may also reduce the proceeds or value to Encana.
The Company may also retain certain liabilities for certain matters in a sale transaction. The magnitude of any such retained liabilities or indemnification obligations may be difficult to quantify at the time of the transaction and could ultimately be material. Further, certain third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after the sale of certain assets, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the purchaser of the assets fails to perform its obligations.
The decision to pay dividends and the amount of such dividends is subject to the discretion of the Board of Directors based on numerous factors and may vary from time to time.
Although the Company currently intends to pay quarterly cash dividends to its shareholders, these cash dividends may vary from time to time and could be increased, reduced or suspended. The amount of cash available to the Company to pay dividends, if any, can vary significantly from period to period for a number of reasons, including, among other things: Encana's operational and financial performance; fluctuations in the costs to produce natural gas, oil and NGLs; the amount of cash required or retained for debt service or repayment; amounts required to fund capital expenditures and working capital requirements; access to equity markets; foreign currency exchange rates and interest rates; and the risk factors set forth in this Annual Report on Form 10-K.
The decision whether or not to pay dividends and the amount of any such dividends are subject to the discretion of the Board of Directors, which regularly evaluates the Company's proposed dividend payments and the solvency test requirements of the CBCA. In addition, the level of dividends per common share will be affected by the number of outstanding common shares and other securities that may be entitled to receive cash dividends or other payments. Dividends may be increased, reduced or suspended depending on the Company's operational success and the performance of its assets. The market value of the common shares may deteriorate if the Company is unable to meet dividend expectations in the future, and that deterioration may be material.
Changes to existing regulations related to income tax laws, royalty regimes, environmental laws or other regulations could adversely affect the Company’s business, financial position, cash flows or results of operations.
Income tax laws, including recent U.S. tax reform and potential U.S. Treasury Department regulations and guidance, royalty regimes, environmental laws or other laws and regulations, and free trade agreements may change or be interpreted in a manner that adversely affects the Company or its securityholders. Tax authorities having jurisdiction over the Company or its shareholders could change their administrative practices, or may disagree with the manner in which the Company calculates its tax liabilities or structures its arrangements, to the detriment of the Company or its securityholders. Changes to existing laws and regulations or the adoption of new laws and regulations could also increase the Company’s cost of compliance and adversely affect the Company’s business, financial position, cash flows or results of operations.
34
Encana does not operate all of its properties and assets and has limited control over factors that could adversely affect the Company’s financial performance.
Other companies operate a portion of the assets in which Encana has ownership interests. Encana may have limited ability to exercise influence over operation of these assets or their associated costs. Encana’s dependence on the operator and other working interest owners for these properties and assets, and its limited ability to influence operations and associated costs, could materially adversely affect the Company’s financial performance. The success and timing of Encana’s activities on assets operated by others therefore will depend upon factors that are outside of the Company’s control, including timing and amount of capital expenditures, timing and amount of operating and maintenance expenditures, the operator’s expertise and financial resources, approval of other participants, selection of technology and risk management practices.
Fluctuations in exchange rates could affect expenses or result in realized and unrealized losses.
Worldwide prices for natural gas and oil are set in U.S. dollars. Although Encana’s financial results are consolidated in Canadian dollars, the Company reports its financial results in U.S. dollars. As Encana operates in both Canada and the U.S., many of the Company’s expenses are incurred outside of the U.S. and are denominated in Canadian dollars. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could impact the Company’s revenue and expenses and have an adverse effect on the Company’s financial performance and condition.
In addition, the Company has U.S. dollar denominated long-term debt. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could result in realized and unrealized losses on U.S. dollar denominated long-term debt.
The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material adverse effect on us.
Encana is exposed to the risks associated with counterparty performance including credit risk and performance risk. Encana may experience material financial losses in the event of customer payment default for commodity sales and financial derivative transactions. Encana’s liquidity may also be impacted if any lender under the Company’s existing credit facilities is unable to fund its commitment. Performance risk can impact Encana’s operations by the non-delivery of contracted products or services by counterparties, which could impact project timelines or operational efficiency.
The Company is subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in the Company’s favour.
Encana may be subject to claims, litigation, administrative proceedings and regulatory actions. The outcome of these matters may be difficult to assess or quantify, and there cannot be any assurance that such matters will be resolved in the Company’s favour. If Encana is unable to resolve such matters favourably, the Company or its directors, officers or employees may become involved in legal proceedings that could result in an onerous or unfavourable decision, including fines, sanctions, monetary damages or the inability to engage in certain operations or transactions. The defence of such matters may also be costly and time consuming, and could divert the attention of management and key personnel from the Company’s operations. Encana may also be subject to adverse publicity associated with such matters, regardless of whether such allegations are valid or whether the Company is ultimately found liable. As a result, such matters could have a material adverse effect on the Company’s reputation, financial position, results of operations or liquidity. See Item 3 of this Annual Report on Form 10-K.
Encana relies on certain key personnel, and if the Company is unable to attract and retain key personnel necessary for its business, Encana’s operations may be negatively impacted.
The Company relies on certain key personnel for the development of its business. The experience, knowledge and contributions of the Company’s existing management team and directors to the immediate and near-term operations and direction of the Company are likely to continue to be of central importance for the foreseeable future. As such, the unexpected loss of services from or retirement of such key personnel could have a material adverse effect on the Company. In addition, the competition for qualified personnel in the oil and gas industry means there can be no
35
assurance that the Company will be able to attract and retain such personnel with the required specialized skills necessary for its business.
Encana has certain indemnification obligations to certain counterparties that could have a material adverse effect on Encana.
Encana has agreed to indemnify or be indemnified by numerous counterparties for certain liabilities and obligations associated with businesses or assets retained or transferred by the Company. Specifically, in relation to a corporate reorganization to split into two independent publicly traded energy companies, Encana and Cenovus Energy Inc. (“Cenovus”) have each agreed to indemnify the other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity, the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the business and assets transferred to Cenovus. Encana also has indemnification obligations under certain acquisition and divestiture activities it has undertaken.
Encana cannot determine whether it will be required to indemnify certain counterparties for any substantial obligations. Encana also cannot be assured that, if a counterparty is required to indemnify Encana and its affiliates for any substantial obligations, such counterparties will be able to satisfy such obligations. Any indemnification claims against Encana pursuant to the provisions of the transaction agreements could have a material adverse effect on Encana.
The Company could be adversely affected by security threats, including cyber-security threats and related disruptions.
The Company has become increasingly dependent upon information technology systems to conduct daily operations. The Company depends on various information technology systems to estimate reserve quantities, process and record financial and operating data, analyze seismic and drilling information, and communicate with employees and third-party partners. This growing dependence on technology is accompanied by greater sensitivity to cyber-attacks and information systems breaches. Unauthorized access to information systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to the Company’s business activities or its competitive position. In addition, the Company’s vendors, suppliers and other business partners may separately suffer disruptions as a result of such security breaches. The potential for such occurrences subjects the Company’s operations to increased risks that could have a material adverse effect on the Company’s business, financial condition and results of operations. To protect its information assets and systems, the Company applies technical and process controls, which are reviewed by the appropriate senior management with oversight from the Company’s Board of Directors. These controls are in line with industry standards and are reviewed annually with peer companies in order to guide Encana’s focus on information security initiatives. However, these controls may not adequately prevent cyber-security breaches.
There is no assurance that the Company will not suffer losses associated with cyber-security breaches in the future. As cyber-attacks continue to evolve, the Company may be required to expend additional resources to investigate, mitigate and remediate any potential vulnerabilities. The Company may also be subject to regulatory investigations or litigation relating to cyber-security issues.
The Company’s operations may be affected by aboriginal treaty, title and other rights.
Aboriginal peoples have claimed aboriginal treaty, title and other rights in respect of areas within Canada and the United States. The Company is not aware of any material claims that have been made in respect of its properties or assets; however, the legal basis of an aboriginal land claim is a matter of considerable legal complexity and the impact of the assertion of such a claim, or the possible effect of a settlement of such claim, upon the Company cannot be predicted with any degree of certainty. In addition, no assurance can be given that any recognition of aboriginal rights or claims whether by way of a negotiated settlement or by judicial pronouncement (or through the grant of an injunction prohibiting exploration or development activities pending resolution of any such claim) would not delay or even prevent the Company’s exploration and development activities. If a material claim were to arise and be successful, such claim could have a material and adverse effect on the Company’s business, financial condition and results of operations. In addition, the process of addressing such claim, regardless of the outcome,
36
could be expensive and time consuming and could result in delays which could have a material and adverse effect on the Company’s business, financial condition and results of operations.
In addition to the foregoing, the Company may become subject to various laws and regulations that apply to operators and other parties operating within the boundaries of Native American reservations in the United States. These laws and regulations may result in the imposition of certain fees, taxes, environmental standards, lease conditions or requirements to employ specified contractors or service providers. Any one of these requirements, or any delay in obtaining the approvals or permits necessary to operate within the boundaries of Native American tribal lands, could adversely impact the Company’s operations and ability to explore and develop new properties.
The Company’s foreign operations expose it to risks abroad which could negatively affect its results of operations.
Certain of Encana’s operations and related assets may be located, from time to time, in countries outside North America, some of which may be considered to be politically and economically unstable. Exploration or development activities in such countries may require protracted negotiations with host governments, national oil companies and third parties and are frequently subject to economic and political considerations, such as taxation, nationalization, expropriation, inflation, currency fluctuations, increased regulation and approval requirements, governmental regulation and the risk of actions by terrorist or insurgent groups, any of which could adversely affect the economics of such exploration or development projects.
Encana is also exposed to risks in connection with certain property interests and production operations in China that were acquired by Encana pursuant to the Newfield acquisition. These risks may include: difficulties obtaining permits or governmental approvals as a foreign operator; currency restrictions, exchange rate fluctuations, or other activities that disrupt markets and restrict the movement of funds; loss of revenue, property and equipment as a result of expropriation, nationalization, war, piracy, acts of terrorism, insurrection, civil unrest and other political risks; disruptions in international oil cargo shipping activities; taxation policies, including increases in taxes and governmental royalties, retroactive tax claims and investment restrictions; physical, digital, internal and external security breaches; forced renegotiation of, unilateral changes to, or termination of contracts with, governmental entities and quasi-governmental agencies; changes in laws and policies governing operations in China; difficulties enforcing rights against a governmental entity due to the doctrine of sovereign immunity; and changes to laws and policies of the United States affecting foreign trade, taxation, investment and transparency matters. Realization of any of the foregoing risks could adversely affect the Company’s business and results of operations.
37
I tem 1 B. Unresolved Staff Comments
None.
Encana is involved in various legal claims and actions arising in the normal course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encana’s financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of a material impact on the Company’s consolidated net earnings or loss for the period in which the effect becomes reasonably estimable. See Item 1A. Risk Factors, “The Company is subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in the Company’s favour.” of this Annual Report on Form 10-K.
For additional information, see Note 25 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
Item 4. Mine Safety Disclosures
Not applicable.
38
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
On February 26, 2018, the Company announced that it had received approval from the TSX to purchase, for cancellation, up to 35 million Encana common shares pursuant to a NCIB over the 12-month period beginning February 28, 2018 and ending February 27, 2019. For the twelve months ended December 31, 2018, the Company purchased approximately 20.7 million common shares for total consideration of approximately $250 million.
On February 13, 2019, the Company confirmed it will proceed with its previously announced plans to spend up to $1.25 billion to purchase common shares, for cancellation, subject to the receipt of regulatory approvals. On February 27, 2019, the TSX accepted the Company’s notice of intention to commence a NCIB for up to approximately 149.4 million Encana common shares, beginning March 4, 2019 and ending March 3, 2020.
MARKET INFORMATION, SHAREHOLDERS, AND DIVIDEND INFORMATION
Market Information
Encana’s common shares are listed and posted for trading on the TSX and NYSE under the symbol “ECA”.
Holders
The Company is authorized to issue an unlimited number of common shares and Class A Preferred Shares limited to a number equal to not more than 20 percent of the issued and outstanding number of common shares at the time of the issuance. As at February 25, 2019, there were 1,495,871,408 common shares outstanding held by 25,686 shareholders of record, and no Class A Preferred Shares outstanding.
Dividend Information
In 2018, Encana paid a quarterly dividend of US$0.015 per share (US$0.06 per share annually). In 2017, Encana paid a quarterly dividend of US$0.015 per share (US$0.06 per share annually). On February 27, 2019 the Board of Directors declared a dividend of US$0.01875 per share payable on March 29, 2019.
Dividend payments are not guaranteed and the amount of cash to be distributed as dividends in the future may change. Any decision to pay dividends will be determined at the discretion of the Board of Directors after consideration of numerous factors including: (i) the earnings of the Company; (ii) financial requirements for the Company’s operations; (iii) the satisfaction by the Company of liquidity and solvency tests described in the CBCA; and (iv) any agreements relating to the Company’s indebtedness that restrict the declaration and payment of dividends. See Item 1A. Risk Factors of this Annual Report on Form 10-K, “The decision to pay dividends and the amount of such dividends is subject to the discretion of the Board of Directors based on numerous factors and may vary from time to time”. The Company currently pays dividends quarterly to shareholders of record as of the 15th day (or the previous business day) of the last month of each calendar quarter, with the last business day of the same month being the corresponding payment date. The dividends paid on the common shares are expected to be designated as “eligible dividends” for Canadian income tax purposes, unless otherwise notified.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
Information concerning securities authorized for issuance under equity compensation plans is set forth in the Proxy Statement relating to the Company’s 2019 annual meeting of shareholders, which is incorporated herein by reference.
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS
None.
39
RECENT SALES OF UNREGISTERED EQUITY SECURITIES
None.
PERFORMANCE GRAPH
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933, as amended (the “Securities Act”) or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.
The following graph compares the cumulative five-year total return to shareholders of Encana’s common shares relative to the cumulative total returns of the S&P/TSX Composite Index and a peer group of 10 comparable companies operating in the same industry as the Company on December 31 for each of the years indicated. The companies included in the peer group are Antero Resources Corporation; Cabot Oil & Gas Corporation; Chesapeake Energy Corporation; Crescent Point Energy Corporation; Enerplus Corporation; Devon Energy Corporation; Obsidian Energy Ltd.; Pengrowth Energy Corporation; Range Resources Corporation; Southwestern Energy Company. The graph was prepared assuming $100 was invested on December 31, 2013 in Encana’s common shares, the S&P 500, the S&P/TSX Composite Index and the peer groups, and dividends have been reinvested subsequent to the initial investment. The graph is included for historical comparative purposes only and should not be considered indicative of future share performance.
40
Comparison of 5-Year Cumulative Total Return Among
Encana Corporation, the S&P 500, the S&P/TSX Composite Index and a Peer Group
|
Fiscal Year Ended December 31 |
2013 |
2014 |
2015 |
2016 |
2017 |
2018 |
|
Encana |
$ 100.00 |
$ 78.00 |
$ 30.00 |
$ 69.00 |
$ 79.00 |
$ 34.00 |
|
Peer Group |
100.00 |
65.00 |
28.00 |
43.00 |
35.00 |
22.00 |
|
S&P 500 |
100.00 |
114.00 |
115.00 |
129.00 |
157.00 |
150.00 |
|
S&P/TSX Composite Index |
100.00 |
111.00 |
101.00 |
123.00 |
134.00 |
122.00 |
41
Item 6: Selected Fin ancial Data
The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2018, which has been derived from the Company’s audited Consolidated Financial Statements. The financial information below should be read in conjunction with Item 7 and Item 8 of this Annual Report on Form 10-K.
|
Year Ended December 31 (US$ millions, unless otherwise specified) |
2018 |
|
|
2017 |
|
|
2016 |
|
|
2015 |
|
|
2014 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Earnings Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
5,939 |
|
|
|
4,443 |
|
|
|
2,918 |
|
|
|
4,422 |
|
|
|
8,019 |
|
|
Impairments |
|
- |
|
|
|
- |
|
|
|
1,396 |
|
|
|
6,473 |
|
|
|
- |
|
|
Operating Income (Loss) (1) |
|
1,694 |
|
|
|
1,068 |
|
|
|
(1,881 |
) |
|
|
(6,298 |
) |
|
|
2,330 |
|
|
Gain (Loss) on Divestitures, Net |
|
5 |
|
|
|
404 |
|
|
|
390 |
|
|
|
14 |
|
|
|
3,426 |
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
1,069 |
|
|
|
827 |
|
|
|
(944 |
) |
|
|
(5,165 |
) |
|
|
3,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Share Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share Basic & Diluted |
|
1.11 |
|
|
|
0.85 |
|
|
|
(1.07 |
) |
|
|
(6.28 |
) |
|
|
4.58 |
|
|
Dividends Declared per Common Share |
|
0.06 |
|
|
|
0.06 |
|
|
|
0.06 |
|
|
|
0.28 |
|
|
|
0.28 |
|
|
Weighted Average Common Shares Outstanding Basic & Diluted (millions) |
|
959.8 |
|
|
|
973.1 |
|
|
|
882.6 |
|
|
|
822.1 |
|
|
|
741.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
1,058 |
|
|
|
719 |
|
|
|
834 |
|
|
|
271 |
|
|
|
338 |
|
|
Total Assets |
|
15,344 |
|
|
|
15,267 |
|
|
|
14,653 |
|
|
|
15,614 |
|
|
|
24,492 |
|
|
Capital Lease Obligations and The Bow Office Building |
|
1,435 |
|
|
|
1,639 |
|
|
|
1,570 |
|
|
|
1,591 |
|
|
|
1,959 |
|
|
Long-Term Debt, Including Current Portion |
|
4,198 |
|
|
|
4,197 |
|
|
|
4,198 |
|
|
|
5,333 |
|
|
|
7,301 |
|
|
Total Shareholders’ Equity |
|
7,447 |
|
|
|
6,728 |
|
|
|
6,126 |
|
|
|
6,167 |
|
|
|
9,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flow Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used In) Operating Activities |
|
2,300 |
|
|
|
1,050 |
|
|
|
625 |
|
|
|
1,681 |
|
|
|
2,667 |
|
|
Non-GAAP Cash Flow (2) |
|
2,115 |
|
|
|
1,343 |
|
|
|
838 |
|
|
|
1,430 |
|
|
|
2,934 |
|
|
Capital Expenditures |
|
1,975 |
|
|
|
1,796 |
|
|
|
1,132 |
|
|
|
2,232 |
|
|
|
2,526 |
|
|
Net Acquisitions & (Divestitures) |
|
(476 |
) |
|
|
(682 |
) |
|
|
(1,052 |
) |
|
|
(1,838 |
) |
|
|
(1,329 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Rates (US$ per C$1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
0.772 |
|
|
0.771 |
|
|
0.755 |
|
|
0.782 |
|
|
0.905 |
|
||||
|
Period End |
|
0.733 |
|
|
0.797 |
|
|
0.745 |
|
|
0.723 |
|
|
0.862 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
89.9 |
|
|
|
76.3 |
|
|
|
73.7 |
|
|
|
87.0 |
|
|
|
49.4 |
|
|
Total NGLs (Mbbls/d) (3) |
|
78.2 |
|
|
|
52.8 |
|
|
|
48.4 |
|
|
|
46.4 |
|
|
|
37.4 |
|
|
Total Oil & NGLs (Mbbls/d) |
|
168.1 |
|
|
|
129.1 |
|
|
|
122.1 |
|
|
|
133.4 |
|
|
|
86.8 |
|
|
Natural Gas (MMcf/d) |
|
1,158 |
|
|
|
1,104 |
|
|
|
1,383 |
|
|
|
1,635 |
|
|
|
2,350 |
|
|
Total Production (MBOE/d) |
|
361.2 |
|
|
|
313.2 |
|
|
|
352.7 |
|
|
|
405.9 |
|
|
|
478.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Prices, Including Realized Gains (Losses) on Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/bbl) |
|
56.84 |
|
|
|
49.76 |
|
|
|
48.68 |
|
|
|
49.68 |
|
|
|
86.03 |
|
|
Total NGLs ($/bbl) (3) |
|
37.21 |
|
|
|
34.72 |
|
|
|
23.90 |
|
|
|
21.66 |
|
|
|
48.09 |
|
|
Oil & NGLs ($/bbl) |
|
47.71 |
|
|
|
43.61 |
|
|
|
38.85 |
|
|
|
39.93 |
|
|
|
69.70 |
|
|
Natural Gas ($/Mcf) |
|
2.76 |
|
|
|
2.42 |
|
|
|
2.10 |
|
|
|
3.89 |
|
|
|
4.59 |
|
|
Total ($/BOE) |
|
31.06 |
|
|
|
26.51 |
|
|
|
21.69 |
|
|
|
28.81 |
|
|
|
35.21 |
|
|
(1) |
Operating income (loss) was restated to conform with the January 1, 2018 adoption of ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The Company reclassified components of total net defined periodic benefit cost, excluding the service cost component, from total operating expenses to other (gains) losses, net in the Consolidated Statement of Earnings by $3 million and $(1) million in 2015 and 2014, respectively. |
|
(2) |
Non-GAAP Cash Flow is a non-GAAP measure and has no standardized meaning under U.S. GAAP. It is used by Management and investors to help assist in measuring Encana’s ability to finance capital programs and meet financial obligations. It is not intended to replace cash from (used in) operating activities as a measure. Non-GAAP Cash Flow is defined and reconciled in the Non-GAAP Measures section under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
|
(3) |
Includes plant condensate. |
Supplemental Quarterly Financial Information (Unaudited)
See Note 28 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10‑K.
42
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The MD&A is intended to provide a narrative description of Encana’s business from management’s perspective. This MD&A should be read in conjunction with the audited Consolidated Financial Statements and accompanying notes for the period ended December 31, 2018 (“Consolidated Financial Statements”), which are included in Item 8 of this Annual Report on Form 10-K. Common industry terms and abbreviations are used throughout this MD&A and are defined in the Definitions, Conversions and Conventions sections of this Annual Report on Form 10-K. This MD&A includes the following sections:
Strategy
By executing on its strategy as outlined in Items 1 and 2 of this Annual Report on Form 10-K, Encana focuses on quality cash flow growth from high margin, scalable, top tier assets located in some of the best plays in North America, referred to as the “Core Assets”. As at December 31, 2018, these comprised Montney and Duvernay in Canada and Eagle Ford and Permian in the U.S. These top tier assets form a multi-basin portfolio of oil, NGL and natural gas producing plays enabling flexible and efficient investment of capital into high margin liquids plays that support sustainable cash flow generation for the Company. Encana rapidly deploys successful ideas and practices across its top tier assets, becoming more efficient as innovative and sustainable technical improvements are implemented.
In executing its strategy, Encana focuses on its core values of One, Agile and Driven, which guide the organization to be flexible, responsive, determined and motivated with a commitment to excellence and a passion to succeed as a unified team.
In evaluating its operations and assessing its leverage, the Company reviews performance-based measures such as Non-GAAP Cash Flow and Non-GAAP Cash Flow Margin and debt-based metrics such as Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA, which are non-GAAP measures and do not have any standardized meaning under U.S. GAAP. These measures may not be similar to measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. Further information regarding these measures, including reconciliations to the closest GAAP measure, can be found in the Non-GAAP Measures section of this MD&A.
43
During 2018, Encana met all of the targets set in its full year 2018 guidance by successfully executing the Company’s 2018 capital plan, maintaining operational efficiencies achieved in 2017 and minimizing the effect of inflationary costs. Higher revenues in 2018 compared to 2017 resulted from higher liquids benchmark prices and production volumes. Higher oil and NGL benchmark prices contributed to increases in Encana’s average realized oil and NGL prices of 30 percent and 15 percent, respectively. Liquids production volumes increased by 30 percent compared to 2017 and represented approximately 47 percent of total production volumes in 2018. Encana also focused on the diversification of the Company’s downstream markets to capture higher realized prices. Encana remains committed to delivering a business model that allows the Company to adapt to fluctuating commodity prices.
Significant Developments
|
|
• |
Announced a definitive merger agreement on November 1, 2018 to acquire all of the issued and outstanding shares of common stock of Newfield in an all stock-transaction. The acquisition closed on February 13, 2019, adding to Encana’s portfolio approximately 360,000 net acres in the oil-rich window of the Anadarko Basin in Oklahoma. Further information on the Newfield acquisition can be found in the Subsequent Events section of this MD&A. |
|
|
• |
Completed the sale of the Company’s San Juan assets in New Mexico to DJR Energy, LLC on December 27, 2018. |
|
|
• |
Completed the sale of the Company’s Pipestone liquids hub in Alberta to Keyera Partnership (“Keyera”), a subsidiary of Keyera Corp., in April 2018. In conjunction with the sale, Keyera will own and construct a natural gas processing facility and will provide Encana with processing services under a competitive fee-for-service arrangement in support of the Company’s liquids growth plans in Montney. |
Financial Results
|
|
• |
Reported net earnings of $1,069 million, including a net gain on risk management in revenues of $415 million, before tax, and a net foreign exchange loss of $168 million, before tax, as well as deferred tax expense of $149 million. |
|
|
• |
Recovered current taxes of approximately $55 million and interest of $17 million primarily due to the successful resolution of certain tax items relating to prior taxation years . |
|
|
• |
Generated cash from operating activities of $2,300 million, Non-GAAP Cash Flow of $2,115 million and Non-GAAP Cash Flow Margin of $16.05 per BOE, including the tax items noted above. Cash from operating activities exceeded capital expenditures by $325 million. |
|
|
• |
Held cash and cash equivalents of $1,058 million and had available credit facilities of $4.0 billion for total liquidity of $5.1 billion at year end. |
|
|
• |
Achieved Net Debt to Adjusted EBITDA of 1.3 times. |
|
|
• |
Returned capital to shareholders through the purchase of approximately 20.7 million common shares for total consideration of approximately $250 million and paid dividends of $0.06 per common share totaling $57 million. |
Capital Investment
|
|
• |
Reported total capital spending of $1,975 million which was in line with the full year 2018 guidance of approximately $2.0 billion. |
|
|
• |
Directed $1,415 million, or 72 percent, of total capital spending to Permian and Montney. |
|
|
• |
Focused on highly efficient capital activity and short-cycle high margin projects providing flexibility to respond to fluctuations in commodity prices. |
44
|
|
• |
Average liquids and natural gas production volumes were in line with the full year 2018 guidance ranges. |
|
|
• |
Produced average oil and NGL volumes of 168.1 Mbbls/d which accounted for 47 percent of total production volumes. Average oil and plant condensate production volumes of 128.9 Mbbls/d were 77 percent of total liquids production volumes. |
|
|
• |
Produced average natural gas volumes of 1,158 MMcf/d which accounted for 53 percent of total production volumes. |
Revenues and Operating Expenses
|
|
• |
Achieved all targets set in the full year 2018 guidance ranges; transportation and processing expense of $7.22 per BOE, as well as upstream operating expense of $3.24 per BOE and administrative expense of $1.43 per BOE, excluding long-term incentive costs. |
|
|
• |
Focused on market diversification to other downstream markets to maximize realized commodity prices and revenues through a combination of derivative financial instruments and transportation contracts. |
|
|
• |
Continued to benefit from secured pipeline transportation capacity to the Dawn and Houston markets to protect against weakening AECO and Midland differentials to NYMEX and WTI, respectively; maintained access to local markets through existing transportation contracts. |
|
|
• |
Incurred higher transportation and processing expense of $238 million in 2018, an increase of 28 percent compared to 2017, primarily due to higher production volumes in Montney and Permian, and additional costs incurred in conjunction with the diversification of other downstream markets to capture higher realized prices as discussed above. |
|
|
• |
Preserved operational efficiencies achieved in previous years and minimized the effect of inflationary costs. |
Subsequent Events
On February 13, 2019, Encana completed the acquisition of all the issued and outstanding shares of common stock of Newfield whereby Encana issued approximately 543.4 million common shares to Newfield shareholders, representing an exchange ratio of 2.6719 Encana common shares for each share of Newfield common stock held. Following the acquisition, Newfield’s senior notes totaling $2.45 billion remain outstanding. Newfield’s operations are focused on the development of oil-rich properties primarily located in the Anadarko Basin in Oklahoma. The post-acquisition results of operations of Newfield will be included in the Company’s interim consolidated results for the period ended March 31, 2019.
On February 13, 2019, the Company confirmed it will proceed with its previously announced plans to spend up to $1.25 billion to purchase common shares, for cancellation, subject to the receipt of regulatory approvals. On February 27, 2019, the Company announced that the TSX accepted its notice of intention to commence a NCIB beginning March 4, 2019 and ending March 3, 2020.
45
Industry Outlook
The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices during 2019 are expected to reflect global supply and demand dynamics as well as the geopolitical environment. At a meeting in December 2018, OPEC and certain non-OPEC countries agreed to reduce crude oil production, beginning in January 2019 for an initial period of six months, seeking to balance the global oil market in response to quickly changing fundamentals. Risks to the global economy including trade disputes, U.S. production growth and potential oil supply outages resulting from geopolitical instability in major producing countries, could further contribute to price fluctuations in 2019. OPEC and certain non-OPEC countries are scheduled to meet again in April 2019 to review production levels which could potentially result in other supply adjustments and contribute to price fluctuations.
Natural gas prices in 2019 will be affected by the timing of supply and demand growth and the effects of seasonal weather. Natural gas prices in western Canada have seen significant negative price pressure as strong supply continues to surpass regional demand and stress effective pipeline capacity. Despite near-term price strength related to lower-than-normal storage and a colder than normal start to winter, potential for improvement in longer-term U.S. natural gas prices remains limited, primarily due to continued production increases in both the Northeast U.S. and associated gas production in the Permian Basin.
Company Outlook
Encana is positioned to be flexible in the current price environment in order to continue to achieve strong returns and to balance growth with return of capital to shareholders. The Company enters into derivative financial instruments which mitigate price volatility and help sustain revenues during periods of lower prices. A portion of the Company’s production is sold at prevailing market prices which also allows Encana to participate in potential price increases. As at February 15, 2019, the Company has hedged approximately 88 Mbbls/d of expected oil and condensate production and 989 MMcf/d of expected natural gas production for the remainder of 2019. Additional information on Encana’s hedging program can be found in Note 23 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Markets for crude oil and natural gas are exposed to different price risks. While the market price for crude oil tends to move in the same direction as the global market, the Permian Basin experienced wide differentials throughout 2018 due to basin export capacity constraints. Recently, these differentials have narrowed and Encana expects this trend to continue in 2019. Natural gas prices may vary between geographic regions depending on local supply and demand conditions. Encana proactively utilizes transportation contracts to diversify the Company’s downstream markets and reduce significant exposure to any given market. Through a combination of derivative financial instruments and transportation capacity, Encana has mitigated the majority of its exposure to Midland and AECO pricing in 2019. In addition, Encana continues to seek new markets to yield higher returns.
Encana’s 2019 guidance, including capital investment, production and operating expenses, reflects the strategic business combination with Newfield. In 2019, as part of the Company’s commitment to returning capital to shareholders, Encana will also increase its dividend by 25 percent and intends to spend up to $1.25 billion to purchase, for cancellation, Encana common shares. Further information can be found in the Subsequent Events, and Liquidity and Capital Resources sections of this MD&A.
Capital Investment
Total anticipated 2019 capital investment of approximately $2.5 billion to $2.7 billion is expected to be primarily funded from 2019 cash generated from operating activities. Capital investment in Permian and Anadarko is expected to be optimized by Encana’s cube development approach to maximize returns and recovery. Capital investment in Montney is expected to be allocated to both Cutbank Ridge and Pipestone with a focus on maximizing returns from high margin liquids. Encana expects to allocate approximately 75 percent of its total capital spending to these three core growth assets in 2019.
Encana continually strives to improve well performance and lower costs through innovative techniques. Encana's large-scale cube development model utilizes multi-well pads and advanced completion designs to access stacked pay
46
resource s to maximize returns and resource recovery from its reservoirs. Encana expect s to deploy the cube development model to the Anadarko Basin assets starting in the second quarter of 2019 . T he application of the cube development is expected to reduce well costs by a pproximately $1 million per well in 2019 compared to Newfield’s 2018 well costs . The impact of Encana’s disciplined capital program and continuous innovation create flexibility and opportunity to grow cash flows and production volumes going forward.
As part of the Company’s long-term growth strategy, Encana has significantly shifted its production mix to a more balanced portfolio in the recent years, thereby reducing the extent of exposure to market volatility of a particular commodity. In 2019, Encana expects to continue to focus on growing liquids production volumes of 290.0 Mbbls/d to 310.0 Mbbls/d and natural gas production volumes of 1,500 MMcf/d to 1,600 MMcf/d. Liquids production is expected to exceed 50 percent of total production volumes in 2019.
Workforce reductions and operating efficiencies attributable to the strategic business combination are expected to reduce indirect operating and administrative costs by approximately $125 million on an annualized basis compared to the aggregate costs of Newfield and Encana prior to the acquisition. These synergies exclude expected restructuring costs to be incurred in 2019. Efficiency improvements and lower service costs are expected to be maintained through the support of the Company’s culture of innovation and its focus on continuous improvement in operational execution. Encana expects to continue pursuing innovative ways to reduce upstream operating and administrative expenses. In 2019, Encana expects total costs of $12.75 per BOE to $13.25 per BOE, which includes upstream transportation and processing expense, operating expense, production, mineral and other taxes, as well as administrative expense. Operating expense and administrative expense excludes long-term incentive costs and restructuring costs. Encana strives to offset any inflationary pressures with efficiency improvements and effective supply chain management, including favorable price negotiations.
Further information on Encana’s 2019 Corporate Guidance can be accessed on the Company’s website at www.encana.com .
47
Selected Financial Information
|
($ millions) |
|
2018 |
|
|
2017 (1) |
|
|
2016 (1) |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product and Service Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream product revenues |
|
$ |
4,223 |
|
|
$ |
3,009 |
|
|
$ |
2,444 |
|
|
Market optimization |
|
|
1,224 |
|
|
|
863 |
|
|
|
647 |
|
|
Service revenues |
|
|
10 |
|
|
|
20 |
|
|
|
31 |
|
|
Total Product and Service Revenues |
|
|
5,457 |
|
|
|
3,892 |
|
|
|
3,122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (Losses) on Risk Management, Net |
|
|
415 |
|
|
|
482 |
|
|
|
(275 |
) |
|
Sublease Revenues |
|
|
67 |
|
|
|
69 |
|
|
|
71 |
|
|
Total Revenues |
|
|
5,939 |
|
|
|
4,443 |
|
|
|
2,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses (2) |
|
|
4,245 |
|
|
|
3,375 |
|
|
|
4,799 |
|
|
Operating Income (Loss) |
|
|
1,694 |
|
|
|
1,068 |
|
|
|
(1,881 |
) |
|
Total Other (Income) Expenses |
|
|
531 |
|
|
|
(362 |
) |
|
|
(261 |
) |
|
Net Earnings (Loss) Before Income Tax |
|
|
1,163 |
|
|
|
1,430 |
|
|
|
(1,620 |
) |
|
Income Tax Expense (Recovery) |
|
|
94 |
|
|
|
603 |
|
|
|
(676 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
$ |
1,069 |
|
|
$ |
827 |
|
|
$ |
(944 |
) |
|
(1) |
2017 and 2016 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”, as described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. |
|
(2) |
Total Operating Expenses include non-cash items such as DD&A, impairments, accretion of asset retirement obligations and long-term incentive costs. |
Encana’s revenues are substantially derived from sales of oil, NGLs and natural gas production. Increases or decreases in Encana’s revenues, profitability and future production are highly dependent on the commodity prices the Company receives. Prices are market driven and fluctuate due to factors beyond the Company’s control, such as supply and demand, seasonality and geopolitical and economic factors. Canadian Operations realized prices are linked to Edmonton Condensate and AECO, as well as other downstream natural gas benchmarks, including Dawn. The USA Operations realized prices generally reflect WTI and NYMEX benchmark prices, as well as other downstream oil benchmarks. The other downstream benchmarks reflect the diversification of the Company’s markets. Realized NGL prices are significantly influenced by oil benchmark prices and the NGL production mix. Recent trends in benchmark prices relevant to Encana are shown in the table below.
Benchmark Prices
|
(average for the period) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs |
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI ($/bbl) |
|
$ |
64.77 |
|
|
$ |
50.95 |
|
|
$ |
43.32 |
|
|
Edmonton Condensate (C$/bbl) |
|
|
78.88 |
|
|
|
66.90 |
|
|
|
56.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX ($/MMBtu) |
|
$ |
3.09 |
|
|
$ |
3.11 |
|
|
$ |
2.46 |
|
|
AECO (C$/Mcf) |
|
|
1.53 |
|
|
|
2.43 |
|
|
|
2.09 |
|
|
Dawn (C$/MMBtu) |
|
|
4.07 |
|
|
|
3.94 |
|
|
|
3.39 |
|
48
Production Volumes and Realized Prices
|
|
|
Production Volumes (1) |
|
|
|
Realized Prices (2) |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
0.4 |
|
|
|
0.4 |
|
|
|
2.0 |
|
|
|
$ |
52.54 |
|
|
$ |
42.33 |
|
|
$ |
36.32 |
|
|
USA Operations |
|
|
89.5 |
|
|
|
75.9 |
|
|
|
71.7 |
|
|
|
|
64.05 |
|
|
|
49.14 |
|
|
|
38.67 |
|
|
Total |
|
|
89.9 |
|
|
|
76.3 |
|
|
|
73.7 |
|
|
|
|
64.00 |
|
|
|
49.10 |
|
|
|
38.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs – Plant Condensate (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
35.2 |
|
|
|
23.1 |
|
|
|
17.6 |
|
|
|
|
56.31 |
|
|
|
50.57 |
|
|
|
40.97 |
|
|
USA Operations |
|
|
3.8 |
|
|
|
3.2 |
|
|
|
2.7 |
|
|
|
|
52.33 |
|
|
|
40.64 |
|
|
|
32.48 |
|
|
Total |
|
|
39.0 |
|
|
|
26.3 |
|
|
|
20.3 |
|
|
|
|
55.92 |
|
|
|
49.35 |
|
|
|
39.84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs – Other (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
14.0 |
|
|
|
6.0 |
|
|
|
7.6 |
|
|
|
|
27.32 |
|
|
|
25.19 |
|
|
|
12.13 |
|
|
USA Operations |
|
|
25.2 |
|
|
|
20.5 |
|
|
|
20.5 |
|
|
|
|
23.39 |
|
|
|
19.42 |
|
|
|
12.53 |
|
|
Total |
|
|
39.2 |
|
|
|
26.5 |
|
|
|
28.1 |
|
|
|
|
24.79 |
|
|
|
20.72 |
|
|
|
12.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total NGLs (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
49.2 |
|
|
|
29.1 |
|
|
|
25.2 |
|
|
|
|
48.05 |
|
|
|
45.35 |
|
|
|
32.32 |
|
|
USA Operations |
|
|
29.0 |
|
|
|
23.7 |
|
|
|
23.2 |
|
|
|
|
27.21 |
|
|
|
22.30 |
|
|
|
14.86 |
|
|
Total |
|
|
78.2 |
|
|
|
52.8 |
|
|
|
48.4 |
|
|
|
|
40.31 |
|
|
|
34.98 |
|
|
|
23.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
49.6 |
|
|
|
29.5 |
|
|
|
27.2 |
|
|
|
|
48.08 |
|
|
|
45.30 |
|
|
|
32.61 |
|
|
USA Operations |
|
|
118.5 |
|
|
|
99.6 |
|
|
|
94.9 |
|
|
|
|
55.03 |
|
|
|
42.74 |
|
|
|
32.84 |
|
|
Total |
|
|
168.1 |
|
|
|
129.1 |
|
|
|
122.1 |
|
|
|
|
52.98 |
|
|
|
43.33 |
|
|
|
32.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d, $/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
1,007 |
|
|
|
838 |
|
|
|
966 |
|
|
|
|
2.24 |
|
|
|
2.16 |
|
|
|
1.77 |
|
|
USA Operations |
|
|
151 |
|
|
|
266 |
|
|
|
417 |
|
|
|
|
2.28 |
|
|
|
3.03 |
|
|
|
2.29 |
|
|
Total |
|
|
1,158 |
|
|
|
1,104 |
|
|
|
1,383 |
|
|
|
|
2.25 |
|
|
|
2.37 |
|
|
|
1.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (MBOE/d, $/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
217.5 |
|
|
|
169.1 |
|
|
|
188.2 |
|
|
|
|
21.34 |
|
|
|
18.61 |
|
|
|
13.82 |
|
|
USA Operations |
|
|
143.7 |
|
|
|
144.1 |
|
|
|
164.5 |
|
|
|
|
47.80 |
|
|
|
35.16 |
|
|
|
24.78 |
|
|
Total |
|
|
361.2 |
|
|
|
313.2 |
|
|
|
352.7 |
|
|
|
|
31.86 |
|
|
|
26.22 |
|
|
|
18.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Mix (%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Plant Condensate |
|
|
36 |
|
|
|
33 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs – Other |
|
|
11 |
|
|
|
8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs |
|
|
47 |
|
|
|
41 |
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
53 |
|
|
|
59 |
|
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Growth - Year Over Year (%) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs |
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Core Asset Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
|
87.6 |
|
|
|
72.6 |
|
|
|
64.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs – Plant Condensate (Mbbls/d) |
|
|
38.9 |
|
|
|
25.8 |
|
|
|
19.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs – Other (Mbbls/d) |
|
|
38.0 |
|
|
|
24.7 |
|
|
|
22.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total NGLs (Mbbls/d) |
|
|
76.9 |
|
|
|
50.5 |
|
|
|
42.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs (Mbbls/d) |
|
|
164.5 |
|
|
|
123.1 |
|
|
|
106.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
1,091 |
|
|
|
826 |
|
|
|
887 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (MBOE/d) |
|
|
346.3 |
|
|
|
260.7 |
|
|
|
254.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of Total Encana Production |
|
|
96 |
|
|
|
83 |
|
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Average daily. |
|
(2) |
Average per-unit prices, excluding the impact of risk management activities. |
|
(3) |
Not adjusted for divestitures. |
49
|
($ millions) |
|
Oil |
|
|
NGLs (1) |
|
|
Natural Gas (2) |
|
|
Total |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 Upstream Product Revenues |
|
$ |
1,041 |
|
|
$ |
424 |
|
|
$ |
978 |
|
|
$ |
2,443 |
|
|
Increase (decrease) due to: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales prices |
|
|
290 |
|
|
|
171 |
|
|
|
201 |
|
|
|
662 |
|
|
Production volumes |
|
|
36 |
|
|
|
79 |
|
|
|
(221 |
) |
|
|
(106 |
) |
|
2017 Upstream Product Revenues |
|
$ |
1,367 |
|
|
$ |
674 |
|
|
$ |
958 |
|
|
$ |
2,999 |
|
|
Increase (decrease) due to: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales prices |
|
|
488 |
|
|
|
139 |
|
|
|
(1 |
) |
|
|
626 |
|
|
Production volumes |
|
|
245 |
|
|
|
339 |
|
|
|
(5 |
) |
|
|
579 |
|
|
2018 Upstream Product Revenues |
|
$ |
2,100 |
|
|
$ |
1,152 |
|
|
$ |
952 |
|
|
$ |
4,204 |
|
|
(1) |
Includes plant condensate. |
|
(2) |
Natural gas revenues for 2018 exclude a royalty adjustment with no associated production volumes of $19 million (2017 - $10 million; 2016 - $1 million). |
Oil Revenues
2018 versus 2017
Oil revenues increased $733 million compared to 2017 primarily due to:
|
|
• |
Higher average realized oil prices of $14.90 per bbl, or 30 percent, increased revenues by $488 million. The increase reflected a higher WTI benchmark price which was up 27 percent and exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets, partially offset by weakening regional pricing relative to the WTI benchmark price in the USA Operations; and |
|
|
• |
Higher average oil production volumes of 13.6 Mbbls/d increased revenues by $245 million. Higher volumes were primarily due to a successful drilling program in Permian (18.4 Mbbls/d), partially offset by natural declines in Eagle Ford (2.8 Mbbls/d). |
2017 versus 2016
Oil revenues increased $326 million compared to 2016 primarily due to:
|
|
• |
Higher average realized oil prices of $10.49 per bbl, or 27 percent, increased revenues by $290 million. The increase reflected a higher WTI benchmark price which was up 18 percent. The increase was also due to higher utilization of pipelines to transport oil to more favourable markets to receive a higher realized price, as well as higher regional pricing in the USA Operations; and |
|
|
• |
Higher average oil production volumes of 2.6 Mbbls/d increased revenues by $36 million. Higher volumes were primarily due to a successful drilling program in Permian (11.6 Mbbls/d), partially offset by the sales of the DJ Basin and Gordondale assets in the third quarter of 2016 and the Tuscaloosa Marine Shale assets in the second quarter of 2017 (5.3 Mbbls/d), natural declines in the USA Other Upstream Operations (1.5 Mbbls/d) and Eagle Ford (1.3 Mbbls/d) and production constraints resulting from Hurricane Harvey in Eagle Ford and Permian during the third quarter of 2017 (0.5 Mbbls/d). |
NGL Revenues
2018 versus 2017
NGL revenues increased $478 million compared to 2017 primarily due to:
|
|
• |
Higher average realized plant condensate prices of $6.57 per bbl, or 13 percent, increased revenues by $91 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 27 percent and 18 percent, respectively, partially offset by changes in regional pricing; and |
|
|
• |
Higher average realized other NGL prices of $4.07 per bbl, or 20 percent, increased revenues by $48 million. The increase reflected higher other NGL benchmark prices in the USA Operations, partially offset by lower other NGL benchmark prices in Canadian Operations; and |
50
|
|
• |
Higher average other NGL production volumes of 12.7 Mbbls/d increased revenues by $107 million. Higher volumes were primarily due to successful drilling programs in Montney and Permian (14.8 Mbbls/d). |
2017 versus 2016
NGL revenues increased $250 million compared to 2016 primarily due to:
|
|
• |
Higher average realized plant condensate prices of $9.51 per bbl, or 24 percent, increased revenues by $93 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 18 percent and 19 percent, respectively; and |
|
|
• |
Higher average realized other NGL prices of $8.30 per bbl, or 67 percent, increased revenues by $78 million resulting from the increase in other NGL benchmark prices; and |
|
|
• |
Higher average plant condensate production volumes of 6.0 Mbbls/d increased revenues by $86 million. Higher volumes were primarily due to successful drilling programs in the Core Assets (7.2 Mbbls/d), partially offset by asset sales (1.1 Mbbls/d), which mainly included the Gordondale and DJ Basin assets in the third quarter of 2016; and |
|
|
• |
Lower average other NGL production volumes of 1.6 Mbbls/d decreased revenues by $7 million. Lower volumes were primarily due to asset sales (5.9 Mbbls/d), which mainly included the Gordondale and DJ Basin assets in the third quarter of 2016, partially offset by successful drilling programs in the Core Assets (5.1 Mbbls/d). |
Natural Gas Revenues
2018 versus 2017
Natural gas revenues decreased $6 million compared to 2017 primarily due to:
|
|
• |
Realized natural gas prices decreased revenues by $1 million resulting from: |
|
|
• |
Lower average realized natural gas prices in the USA Operations of $0.75 per Mcf decreased revenues by $42 million primarily due to weakening regional pricing; and |
|
|
• |
Higher average realized natural gas prices in Canadian Operations of $0.08 per Mcf increased revenues by $41 million primarily due to exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets, partially offset by a lower AECO benchmark price which was down 37 percent. |
|
|
• |
Production volume changes decreased revenues by $5 million resulting from: |
|
|
• |
Lower average production volumes in the USA Operations of 115 MMcf/d decreased revenues by $128 million primarily due to the sale of the Piceance natural gas assets in the third quarter of 2017 (129 MMcf/d), partially offset by a successful drilling program in Permian in 2018 (23 MMcf/d); and |
51
Natural gas revenues decreased $20 million compared to 2016 primarily due to:
|
|
• |
Lower average natural gas production volumes of 279 MMcf/d decreased revenues by $221 million. Lower volumes were primarily due to asset sales (198 MMcf/d) which mainly included the Piceance natural gas assets in the third quarter of 2017 and the Gordondale and DJ Basin assets in the third quarter of 2016, natural declines in Other Upstream Operations (77 MMcf/d) and increased downtime resulting from scheduled third-party plant maintenance in Montney (19 MMcf/d), partially offset by a successful drilling program in Permian (17 MMcf/d); |
partially offset by:
|
|
• |
Higher average realized natural gas prices of $0.44 per Mcf, or 23 percent, increased revenues by $201 million. The increase reflected higher NYMEX, AECO and Algonquin City Gate benchmark prices which were up 26 percent, 16 percent and 19 percent, respectively. The increase was also due to the diversification of the Company’s downstream markets to capture a higher realized price. |
Gains (Losses) on Risk Management, Net
As a means of managing commodity price volatility, Encana enters into commodity derivative financial instruments on a portion of its expected oil, NGL and natural gas production volumes. The Company’s commodity price mitigation program reduces volatility and helps sustain revenues during periods of lower prices. Further information on the Company’s commodity price positions as at December 31, 2018 can be found in Note 23 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
The following table provides the effects of Encana’s risk management activities on revenues.
|
|
|
$ millions |
|
|
|
Per-Unit |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gains (Losses) on Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/bbl) |
|
$ |
(235 |
) |
|
$ |
18 |
|
|
$ |
271 |
|
|
|
$ |
(7.16 |
) |
|
$ |
0.66 |
|
|
$ |
10.07 |
|
|
NGLs ($/bbl) (2) |
|
|
(89 |
) |
|
|
(5 |
) |
|
- |
|
|
|
|
(3.10 |
) |
|
|
(0.26 |
) |
|
|
(0.04 |
) |
|
|
Natural Gas ($/Mcf) |
|
|
218 |
|
|
|
20 |
|
|
|
85 |
|
|
|
|
0.51 |
|
|
|
0.05 |
|
|
|
0.17 |
|
|
Other (3) |
|
|
2 |
|
|
|
7 |
|
|
|
5 |
|
|
|
- |
|
|
- |
|
|
- |
|
|||
|
Total ($/BOE) |
|
|
(104 |
) |
|
|
40 |
|
|
|
361 |
|
|
|
$ |
(0.80 |
) |
|
$ |
0.29 |
|
|
$ |
2.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Gains (Losses) on Risk Management |
|
|
519 |
|
|
|
442 |
|
|
|
(636 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains (Losses) on Risk Management, Net |
|
$ |
415 |
|
|
$ |
482 |
|
|
$ |
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Includes realized gains and losses related to the Canadian and USA Operations. |
|
(2) |
Includes plant condensate. |
|
(3) |
Other primarily includes realized gains or losses from Market Optimization and other derivative contracts with no associated production volumes. |
Encana recognizes fair value changes from its risk management activities each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationship between contract prices and the associated forward curves. Realized gains or losses on risk management activities related to commodity price mitigation are included in the Canadian and USA Operations and Market Optimization revenues as the contracts are cash settled . Unrealized gains or losses on fair value changes of unsettled contracts are included in the Corporate and Other segment.
52
Market Optimization product revenues relate to activities that provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification.
|
($ millions) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
$ |
1,224 |
|
|
$ |
863 |
|
|
$ |
647 |
|
2018 versus 2017
Market Optimization revenues increased $361 million compared to 2017 primarily due to:
|
|
• |
Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with certain divestitures from prior years ($436 million), partially offset by lower natural gas benchmark prices ($75 million). |
2017 versus 2016
Market Optimization revenues increased $216 million compared to 2016 primarily due to:
|
|
• |
Higher natural gas benchmark prices ($166 million) and higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with certain divestitures from prior years ($50 million). |
Sublease Revenues
Sublease revenues primarily includes amounts related to the sublease of office space in The Bow office building recorded in the Corporate and Other segment. Further information on The Bow office sublease can be found in Note 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
53
Production, Mineral and Other Taxes
Production, mineral and other taxes include production and property taxes. Production taxes are generally assessed as a percentage of oil and natural gas production revenues. Property taxes are generally assessed based on the value of the underlying assets.
|
|
|
$ millions |
|
|
|
$/BOE |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
16 |
|
|
$ |
20 |
|
|
$ |
23 |
|
|
|
$ |
0.20 |
|
|
$ |
0.33 |
|
|
$ |
0.33 |
|
|
USA Operations |
|
|
131 |
|
|
|
92 |
|
|
|
76 |
|
|
|
$ |
2.50 |
|
|
$ |
1.74 |
|
|
$ |
1.27 |
|
|
Total |
|
$ |
147 |
|
|
$ |
112 |
|
|
$ |
99 |
|
|
|
$ |
1.11 |
|
|
$ |
0.98 |
|
|
$ |
0.77 |
|
2018 versus 2017
Production, mineral and other taxes increased $35 million compared to 2017 primarily due to:
|
|
• |
Higher liquids prices in Permian and Eagle Ford and higher production volumes in Permian ($40 million) and lower production taxes in 2017 from tax recoveries in the USA Operations ($8 million) ; |
partially offset by :
|
|
• |
Asset sales ($15 million), which mainly include certain assets in Wheatland in the fourth quarter of 2017 and the Piceance natural gas assets in the third quarter of 2017. |
2017 versus 2016
Production, mineral and other taxes increased $1 3 million compared to 2016 primarily due to:
|
|
• |
Higher prices in the USA Operations and higher liquids production volumes in Permian ($ 31 million) ; |
partially offset by :
|
|
• |
The sales of the DJ Basin and Gordondale assets in the third quarter of 2016 and the Piceance natural gas assets in the third quarter of 2017 ($ 10 million) and the recovery of certain production taxes in the USA Operations ($8 million). |
Transportation and Processing
Transportation and processing expense includes transportation costs incurred to move product from production points to sales points including gathering, compression, pipeline tariffs, trucking and storage costs. Encana also incurs costs related to processing provided by third parties or through ownership interests in processing facilities to bring raw production to sales-quality product.
|
|
|
$ millions |
|
|
|
$/BOE |
|
||||||||||||||||||
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
828 |
|
|
$ |
578 |
|
|
$ |
576 |
|
|
|
$ |
10.42 |
|
|
$ |
9.35 |
|
|
$ |
8.35 |
|
|
USA Operations |
|
|
124 |
|
|
|
164 |
|
|
|
260 |
|
|
|
$ |
2.37 |
|
|
$ |
3.12 |
|
|
$ |
4.33 |
|
|
Upstream Transportation and Processing |
|
|
952 |
|
|
|
742 |
|
|
|
836 |
|
|
|
$ |
7.22 |
|
|
$ |
6.49 |
|
|
$ |
6.48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
131 |
|
|
|
103 |
|
|
|
87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
- |
|
|
- |
|
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Total |
|
$ |
1,083 |
|
|
$ |
845 |
|
|
$ |
901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
Transportation and processing expense increased $238 million compared to 2017 primarily due to:
|
|
• |
Higher production volumes and gathering and processing fees in Montney ($147 million) and Permian ($15 million), higher downstream processing and transportation costs due to higher volumes and costs relating to the diversification of the Company’s downstream markets in Montney ($137 million) and Permian ($24 million); |
partially offset by:
|
|
• |
Asset sales ($67 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017, and lower volumes from Deep Panuke where the Company has ceased operations and has begun planning decommissioning activities ($23 million). |
2017 versus 2016
Transportation and processing expense decreased $56 million compared to 2016 primarily due to:
|
|
• |
Asset sales ($107 million), which mainly include the DJ Basin and Gordondale assets in the third quarter of 2016 and the Piceance natural gas assets in the third quarter of 2017 , the renegotiation and expiration of certain transportation contracts ($ 32 million), lower natural gas production volumes and lower gas gathering and processing fees in Montney and Other Upstream Operations ($ 9 million) and lower activity in Duvernay ($4 million); |
partially offset by:
|
|
• |
Increased downstream processing and transportation costs primarily in Montney and Duvernay due to Encana’s focus on liquids rich wells in the plays and costs relating to the diversification of the Company’s downstream markets ($40 million), higher volumes and prices in Permian ($ 25 million), unrealized risk management gains on power financial derivative contracts in 2016 ($22 million) and the higher U.S./Canadian dollar exchange rate ($ 11 million). |
Operating
Operating expense includes costs paid by Encana, net of amounts capitalized, to operate oil and gas properties in which the Company has a working interest. These costs primarily include labour, service contract fees, chemicals and fuel.
|
|
|
$ millions |
|
|
|
$/BOE |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
118 |
|
|
$ |
122 |
|
|
$ |
152 |
|
|
|
$ |
1.45 |
|
|
$ |
1.92 |
|
|
$ |
2.16 |
|
|
USA Operations |
|
|
305 |
|
|
|
331 |
|
|
|
394 |
|
|
|
$ |
5.80 |
|
|
$ |
6.18 |
|
|
$ |
6.44 |
|
|
Upstream Operating Expense (1) |
|
|
423 |
|
|
|
453 |
|
|
|
546 |
|
|
|
$ |
3.18 |
|
|
$ |
3.88 |
|
|
$ |
4.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
16 |
|
|
|
35 |
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
15 |
|
|
|
18 |
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
454 |
|
|
$ |
506 |
|
|
$ |
598 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
2018 Upstream Operating Expense per BOE includes a recovery of long-term incentive costs of $0.06/BOE (2017 - long-term incentive costs of $0.19/BOE; 2016 - long-term incentive costs of $0.29/BOE). |
55
Operating expense decreased $52 million compared to 2017 primarily due to:
partially offset by:
2017 versus 2016
Operating expense decreased $92 million compared to 2016 primarily due to:
|
|
• |
Asset sales ($66 million), which mainly included the DJ Basin and Gordondale assets in the third quarter of 2016, the Piceance natural gas assets in the third quarter of 2017 and the Tuscaloosa Marine Shale assets in the second quarter of 2017, lower salaries and benefits and long-term incentive costs due to higher headcount dedicated to the capital program and a smaller increase in Encana’s share price in 2017 compared to 2016 ($47 million) and cost-saving initiatives ($24 million); |
partially offset by:
|
|
• |
Higher activity in Permian and Montney ($39 million) and the higher U.S./Canadian dollar exchange rate ($ 4 million) . |
Further information on Encana’s long-term incentives can be found in Note 20 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Purchased product expense includes purchases of oil, NGLs and natural gas from third parties that are used to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification.
|
($ millions) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
$ |
1,100 |
|
|
$ |
788 |
|
|
$ |
586 |
|
2018 versus 2017
Purchased product expense increased $312 million compared to 2017 primarily due to:
|
|
• |
Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with certain divestitures from prior years ($423 million), partially offset by lower natural gas benchmark prices ($111 million). |
2017 versus 2016
Purchased product expense increased $ 202 million compared to 2016 primarily due to:
|
|
• |
Higher natural gas benchmark prices ($ 152 million) and higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with certain divestitures from prior years ($ 50 million). |
56
Depreciation, Depletion & Amortization
Proved properties within each country cost centre are depleted using the unit-of-production method based on proved reserves as discussed in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K . Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates, as well as fluctuations in 12-month average trailing prices which affect proved reserves volumes. Additional information can be found in the Critical Accounting Estimates section of this MD&A under Upstream Assets and Reserve Estimates. Corporate assets are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets.
|
|
|
$ millions |
|
|
|
$/BOE |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
361 |
|
|
$ |
236 |
|
|
$ |
260 |
|
|
|
$ |
4.55 |
|
|
$ |
3.82 |
|
|
$ |
3.77 |
|
|
USA Operations |
|
|
860 |
|
|
|
530 |
|
|
|
523 |
|
|
|
$ |
16.39 |
|
|
$ |
10.09 |
|
|
$ |
8.68 |
|
|
Upstream DD&A |
|
|
1,221 |
|
|
|
766 |
|
|
|
783 |
|
|
|
$ |
9.26 |
|
|
$ |
6.70 |
|
|
$ |
6.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
1 |
|
|
|
1 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
50 |
|
|
|
66 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,272 |
|
|
$ |
833 |
|
|
$ |
859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 versus 2017
DD&A increased $439 million compared to 2017 primarily due to:
|
|
• |
Higher depletion rates in the USA and Canadian Operations ($318 million and $67 million, respectively) and higher production volumes in Canadian Operations ($59 million). |
The depletion rates in the Canadian and USA Operations increased $0.73 per BOE and $6.30 per BOE, respectively, compared to 2017 primarily due to:
|
|
• |
Higher capital spending resulting from an increased capital program in 2018, transfers of unproved property costs of previously acquired assets which have been evaluated for proved reserves and lower reserve volumes from the sale of the Piceance natural gas assets in the USA Operations in the third quarter of 2017. |
2017 versus 2016
DD&A decreased $ 26 million compared to 2016 primarily due to:
|
|
• |
Lower production volumes ($ 85 million) and lower straight-line depreciation on corporate assets ($12 million), partially offset by higher depletion rates primarily in the USA Operations ($63 million) and the higher U.S./Canadian dollar exchange rate ($5 million). |
The depletion rates in the Canadian and USA Operations increased $0.05 per BOE and $1.41 per BOE, respectively, compared to 2016 primarily due to:
|
|
• |
Lower reserve volumes from the sale of the Piceance natural gas assets in the third quarter of 2017, partially offset by ceiling test impairments recognized in the first six months of 2016 in the Canadian and USA Operations, and the sale of the DJ Basin assets in the third quarter of 2016. The sale of the Piceance natural gas assets resulted in the recognition of a gain on divestiture, whereas proceeds from the sale of the DJ Basin assets were deducted from the U.S. full cost pool. Additional information on the divestitures can be found in Note 8 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. |
57
Under full cost accounting, the carrying amount of Encana’s oil and natural gas properties within each country cost centre is subject to a ceiling test at the end of each quarter. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum of the estimated after-tax future net cash flows from proved reserves as calculated under SEC requirements using the 12-month average trailing prices and discounted at 10 percent.
|
($ millions) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
493 |
|
|
USA Operations |
|
|
- |
|
|
|
- |
|
|
|
903 |
|
|
Total |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,396 |
|
The Company did not recognize any ceiling test impairments for 2018 and 2017. The ceiling test impairments in 2016 were primarily due to the decline in the 12-month average trailing prices, which reduced the Canadian and USA Operations proved reserves volumes and values as calculated under SEC requirements. For additional information on the 12-month average trailing prices used in the ceiling test calculations, refer to Note 27 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Administrative
Administrative expense represents costs associated with corporate functions provided by Encana staff in the Calgary and Denver offices. Costs primarily include salaries and benefits, general office, information technology and long-term incentive costs.
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administrative ($ millions) |
|
$ |
157 |
|
|
$ |
254 |
|
|
$ |
309 |
|
|
Administrative ($/BOE) (1) |
|
$ |
1.18 |
|
|
$ |
2.22 |
|
|
$ |
2.40 |
|
|
(1) |
2018 administrative expense per BOE includes a recovery of long-term incentive costs of $0.25/BOE (2017 - long-term incentive costs of $0.67/BOE). 2016 administrative expense per BOE includes long-term incentive costs and restructuring costs of $0.93/BOE. |
2018 versus 2017
Administrative expense in 2018 decreased $97 million compared to 2017 primarily due to lower long-term incentive costs resulting from the decrease in Encana’s share price in 2018 compared to 2017 ($109 million).
2017 versus 2016
Administrative expense in 2017 decreased $55 million compared to 2016 primarily due to lower restructuring costs ($34 million), lower third-party payments relating to previously divested assets ($11 million) as well as lower long-term incentive costs resulting from a smaller increase in Encana’s share price in 2017 compared to 2016 ($10 million).
58
|
($ millions) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
$ |
351 |
|
|
$ |
363 |
|
|
$ |
397 |
|
|
Foreign Exchange (Gain) Loss, Net |
|
|
168 |
|
|
|
(279 |
) |
|
|
(210 |
) |
|
(Gain) Loss on Divestitures, Net |
|
|
(5 |
) |
|
|
(404 |
) |
|
|
(390 |
) |
|
Other (Gains) Losses, Net |
|
|
17 |
|
|
|
(42 |
) |
|
|
(58 |
) |
|
Total Other (Income) Expenses |
|
$ |
531 |
|
|
$ |
(362 |
) |
|
$ |
(261 |
) |
Interest
Interest expense primarily includes interest on Encana’s long-term debt arising from U.S. dollar denominated unsecured notes. Encana also incurs interest on the Company’s long-term obligations for The Bow office building and capital leases. Further details on changes in interest can be found in Note 4 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
2018 versus 2017
Interest expense in 2018 decreased $12 million compared to 2017 primarily due to a $17 million recovery of other interest resulting from the successful resolution of certain tax items related to prior taxation years compared to $11 million in 2017, and lower interest on capital leases ($4 million) .
2017 versus 2016
Interest expense in 2017 decreased $34 million compared to 2016 primarily due to lower interest on debt ($29 million) resulting from the early retirement of long-term debt in March 2016. Further information on the March 2016 debt retirement can be found in the Liquidity and Capital Resources section of this MD&A.
Foreign Exchange (Gain) Loss, Net
Foreign exchange gains and losses result from the impact of fluctuations in the Canadian to U.S. dollar exchange rate. Further details on changes in foreign exchange gains or losses can be found in Note 5 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Additional information on foreign exchange rates and the effects of foreign exchange rate changes can be found in Items 6 and 7A of this Annual Report on Form 10-K.
2018 versus 2017
In 2018, Encana recorded a net foreign exchange loss of $168 million compared to a net gain of $279 million in 2017. The change of $447 million was primarily due to unrealized foreign exchange losses on the translation of U.S. dollar financing debt issued from Canada compared to gains in 2017 ($601 million) and unrealized losses on the translation of U.S. dollar risk management contracts issued from Canada compared to gains in 2017 ($68 million), partially offset by higher unrealized foreign exchange gains on the translation of intercompany notes ($145 million) and realized foreign exchange gains on the settlement of intercompany notes compared to losses in 2017 ($59 million).
2017 versus 2016
In 2017, Encana recorded a higher net foreign exchange gain compared to 2016 ($69 million). The change was primarily due to higher unrealized foreign exchange gains on the translation of U.S. dollar financing debt issued from Canada ($113 million) and unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada compared to losses in 2016 ($48 million), partially offset by realized foreign exchange losses on the settlement of U.S. dollar financing debt issued from Canada compared to gains in 2016 ($87 million). In 2017, unrealized foreign exchange on the translation of U.S. dollar financing debt issued from Canada included an out-of-period adjustment of $68 million, before tax, in respect of unrealized losses on a foreign-denominated capital lease obligation since December 31, 2013. Further information on the out-of-period adjustment can be found in Note 5 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
59
(Gain) Loss on Divestitures, Net
Amounts received from the Company’s divestiture transactions are deducted from the respective Canadian and U.S. full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost centre, in which case a gain or loss is recognized. Additional information regarding gains on divestitures can be found in Note 8 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
2017
Gain on divestitures in 2017 primarily included the before tax gain on the sale of the Piceance natural gas assets of approximately $406 million.
2016
Gain on divestitures in 2016 primarily included the gain on the sale of the Gordondale assets of approximately $394 million.
Other (Gains) Losses, Net
Other (gains) losses, net, primarily includes other non-recurring revenues or expenses and may also include items such as interest income on short-term investments, interest received from tax authorities, reclamation charges relating to decommissioned assets and adjustments related to other assets.
2018
Other losses in 2018 primarily includes the write-down of long-term receivables relating to Other Upstream Operations of $20 million, acquisition costs relating to the merger agreement with Newfield of $7 million, and reclamation charges relating to decommissioned assets of $4 million , partially offset by interest income on short-term investments of $8 million and the recovery of sales taxes relating to previously divested investments of $7 million.
2017
Other gains in 2017 primarily included interest received of $33 million resulting from the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years and interest income on short-term investments of $6 million, partially offset by reclamation charges relating to decommissioned assets of $4 million.
2016
Other gains in 2016 primarily included a gain of $89 million on the early retirement of long-term debt as discussed in the Liquidity and Capital Resources section of this MD&A, partially offset by a one-time third-party payment relating to a previously divested asset of $20 million and reclamation charges relating to decommissioned assets of $7 million .
60
|
($ millions) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Income Tax Expense (Recovery) |
|
$ |
(55 |
) |
|
$ |
(63 |
) |
|
$ |
(78 |
) |
|
Deferred Income Tax Expense (Recovery) |
|
|
149 |
|
|
|
666 |
|
|
|
(598 |
) |
|
Income Tax Expense (Recovery) |
|
$ |
94 |
|
|
$ |
603 |
|
|
$ |
(676 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective Tax Rate |
|
|
8.1 |
% |
|
|
42.2 |
% |
|
|
41.7 |
% |
Income Tax Expense (Recovery)
2018 versus 2017
Total income tax expense in 2018 decreased $509 million compared to 2017 mainly as a result of lower deferred income tax expense ($517 million) which was primarily due to:
|
|
• |
Lower net earnings before income tax in 2018 compared to 2017 ($267 million); and |
|
|
• |
A reduction in the 2018 U.S. federal corporate tax rate from 35 percent to 21 percent resulting from U.S. Tax Reform. |
The current income tax recovery in 2018 of $55 million was primarily due to the successful resolution of certain tax items relating to prior taxation years.
There has been no change in 2018 to the provisional tax adjustment of $327 million recognized in December 2017 resulting from the re-measurement of the Company’s tax position due to a reduction of the U.S. federal corporate tax rate under U.S. Tax Reform. As at December 31, 2018, the Company has completed its assessment of the income tax effects in respect of the provisional adjustment related to U.S. Tax Reform. Additional information on U.S. Tax Reform can be found in Note 6 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
2017 versus 2016
Total income tax in 2017 was an expense of $603 million compared to a recovery of $676 million in 2016 mainly as a result of d eferred income tax expense in 2017 of $666 million compared to a recovery of $598 million in 2016. The deferred income tax was primarily due to:
|
|
• |
Net earnings before income tax in 2017 of $1,430 million compared to a net loss before income tax of $1,620 million in 2016; and |
|
|
• |
Deferred tax expense in 2017 included a provisional adjustment of $327 million resulting from U.S. Tax Reform as discussed above; and |
|
|
• |
Deferred tax recovery in 2016 was primarily due to the recognition of non-cash ceiling test impairments of $1,396 million, before tax . |
The current income tax recovery in 2017 of $63 million was primarily due to the successful resolution of certain tax items previously assessed by the taxing authorities relating to prior taxation years, as well as the reclassification of $10 million of U.S. alternative minimum tax to a long-term receivable from a deferred tax asset due to U.S. Tax Reform.
Effective Tax Rate
Encana’s annual effective income tax rate is primarily impacted by earnings, income tax related to foreign operations, the effect of legislative changes including U.S. Tax Reform, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. Additional information on income taxes can be found in Note 6 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
The effective tax rate for 2018 was 8.1 percent, which is lower than the Canadian statutory rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to
61
jurisdictional earnings, partnership tax allocations in excess of funding and the successful resolution of certain tax items relating to prior taxation years.
The effective tax rate for 2017 was 42.2 percent, which was higher than the Canadian statutory tax rate of 27 percent primarily due to U.S. Tax Reform, which increased Encana’s effective tax rate by 22.9 percent, as well as the impacts from tax reassessments discussed above. The effective tax rate for 2016 exceeded the Canadian statutory tax rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings.
Tax interpretations, regulations and legislation, including U.S. Tax Reform and potential Treasury Department regulations and guidance, in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. As a result, there are tax matters under review for which the timing of resolution is uncertain. The Company believes that the provision for income taxes is adequate.
62
Liquidity and Ca pital Resources
Sources of Liquidity
The Company has the flexibility to access cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities as well as debt and equity capital markets. Encana closely monitors the accessibility of cost-effective credit and ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. In addition, the Company may use cash and cash equivalents, cash from operating activities, or proceeds from asset divestitures and share issuances to fund its operations or to manage its capital structure as discussed below. At December 31, 2018, $711 million in cash and cash equivalents was held by U.S. subsidiaries. The cash held by U.S. subsidiaries is accessible and may be subject to additional Canadian income taxes and U.S. withholding taxes if repatriated.
The Company’s capital structure consists of total shareholders’ equity plus long-term debt, including the current portion. The Company’s objectives when managing its capital structure are to maintain financial flexibility to preserve Encana’s access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. Encana has a practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, purchasing shares for cancellation through a NCIB, issuing new debt or repaying existing debt.
|
($ millions, except as indicated) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
$ |
1,058 |
|
|
$ |
719 |
|
|
$ |
834 |
|
|
Available Credit Facility – Encana (1) |
|
|
2,500 |
|
|
|
3,000 |
|
|
|
3,000 |
|
|
Available Credit Facility – U.S. Subsidiary (1) |
|
|
1,500 |
|
|
|
1,500 |
|
|
|
1,500 |
|
|
Total Liquidity |
|
|
5,058 |
|
|
|
5,219 |
|
|
|
5,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt, including current portion |
|
|
4,198 |
|
|
|
4,197 |
|
|
|
4,198 |
|
|
Total Shareholders’ Equity |
|
|
7,447 |
|
|
|
6,728 |
|
|
|
6,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt to Capitalization (%) (2) |
|
|
36 |
|
|
|
38 |
|
|
|
41 |
|
|
Debt to Adjusted Capitalization (%) (3) |
|
|
22 |
|
|
|
22 |
|
|
|
23 |
|
|
(1) |
Collectively, the “Credit Facilities”. |
|
(2) |
Calculated as long-term debt, including the current portion, divided by shareholders’ equity plus long-term debt, including the current portion. |
|
(3) |
A non-GAAP measure which is defined in the Non-GAAP Measures section of this MD&A. |
In the first quarter of 2018, the Company amended the capacity of its Encana Credit Facility from $3.0 billion to $2.5 billion and extended the maturity for both Credit Facilities to July 2022.
Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is a non-GAAP measure defined in the Non-GAAP Measures section of this MD&A, as a proxy for Encana’s financial covenant under the Credit Facilities, which requires debt to adjusted capitalization to be less than 60 percent. The definitions used in the covenant under the Credit Facilities adjust capitalization for cumulative historical ceiling test impairments that were recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Additional information on financial covenants can be found in Note 13 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
63
During 2018, Encana primarily generated cash through operating activities. The following table summarizes the sources and uses of the Company’s cash and cash equivalents.
|
($ millions) |
Activity Type |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sources of Cash and Cash Equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from operating activities |
Operating |
|
|
$ |
2,300 |
|
|
$ |
1,050 |
|
|
$ |
625 |
|
|
Proceeds from divestitures |
Investing |
|
|
|
493 |
|
|
|
736 |
|
|
|
1,262 |
|
|
Issuance of common shares, net of offering costs |
Financing |
|
|
|
- |
|
|
|
- |
|
|
|
1,129 |
|
|
Other |
Investing |
|
|
|
- |
|
|
|
77 |
|
|
|
51 |
|
|
|
|
|
|
|
2,793 |
|
|
|
1,863 |
|
|
|
3,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of Cash and Cash Equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
Investing |
|
|
|
1,975 |
|
|
|
1,796 |
|
|
|
1,132 |
|
|
Acquisitions |
Investing |
|
|
|
17 |
|
|
|
54 |
|
|
|
210 |
|
|
Net repayment of revolving long-term debt |
Financing |
|
|
|
- |
|
|
|
- |
|
|
|
650 |
|
|
Repayment of long-term debt |
Financing |
|
|
|
- |
|
|
|
- |
|
|
|
400 |
|
|
Purchase of common shares |
Financing |
|
|
|
250 |
|
|
|
- |
|
|
|
- |
|
|
Dividends on common shares |
Financing |
|
|
|
56 |
|
|
|
57 |
|
|
|
51 |
|
|
Other |
Investing/Financing |
|
|
|
146 |
|
|
|
82 |
|
|
|
66 |
|
|
|
|
|
|
|
2,444 |
|
|
|
1,989 |
|
|
|
2,509 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
|
|
|
(10 |
) |
|
|
11 |
|
|
|
5 |
|
|
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
$ |
339 |
|
|
$ |
(115 |
) |
|
$ |
563 |
|
Operating Activities
Cash from operating activities in 2018 was $2,300 million and was primarily a reflection of increases in liquids production volumes, recovering realized liquids prices, the Company’s efforts in maintaining cost efficiencies achieved in previous years and changes in non-cash working capital. Additional detail on changes in non-cash working capital can be found in Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Encana expects it will continue to meet the payment terms of its suppliers.
Non-GAAP Cash Flow in 2018 was $2,134 million and was primarily impacted by the items affecting cash from operating activities which are discussed below and in the Results of Operations section of this MD&A.
2018 versus 2017
Net cash from operating activities increased $1,250 million compared to 2017 primarily due to:
|
|
• |
Higher liquids production volumes ($584 million) and realized liquids prices ($627 million), changes in non-cash working capital ($498 million) and higher natural gas production volumes and realized natural gas prices in Canadian Operations ($123 million and $41 million, respectively); |
partially offset by:
|
|
• |
Higher transportation and processing expense ($238 million), realized losses on risk management in revenues in 2018 compared to gains in 2017 ($144 million), lower natural gas production volumes and realized natural gas prices in the USA Operations ($128 million and $42 million, respectively), higher production, mineral and other taxes ($35 million) and lower interest income recorded in other gains (losses), net ($30 million). |
64
Net cash from operating activities increased $ 425 million compared to 2016 primarily due to:
|
|
• |
Higher realized commodity prices ($662 million), higher liquids production volumes ($115 million), lower operating expense, excluding non-cash long-term incentive costs ($73 million), lower transportation and processing expense ($56 million), higher interest income recorded in other gains ($39 million), lower restructuring costs ($34 million) and lower interest on long-term debt ($29 million); |
partially offset by:
|
|
• |
Lower realized gains on risk management included in revenues ($321 million), lower natural gas production volumes ($221 million) and changes in non-cash working capital ($66 million). |
Investing Activities
Capital expenditures and divestitures have been Encana’s primary investing activities over the past three years. The capital spending program increased in 2018 compared to 2017 as liquids prices continued to recover. Capital expenditures and divestiture activity are summarized in Notes 2 and 8, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
2018
Net cash used in investing activities in 2018 was $1,555 million primarily due to capital expenditures, partially offset by proceeds from divestitures. Capital expenditures in 2018 increased $179 million compared to 2017 due to the increase in Encana’s capital program for 2018. This increase was primarily in Montney ($170 million), Eagle Ford ($90 million), and Duvernay ($39 million), partially offset by lower capital expenditures in Permian ($102 million). Cash from operating activities exceeded capital expenditures by $325 million.
Acquisitions in 2018 were $17 million, which primarily included purchases with oil and liquids rich potential.
Divestitures in 2018 were $493 million, which primarily included the sale of the San Juan assets in New Mexico, comprising approximately 182,000 net acres, and the sale of the Pipestone midstream assets in Alberta.
2017
Net cash used in investing activities in 2017 was $1,037 million primarily due to capital expenditures, partially offset by proceeds from divestitures. Capital expenditures in 2017 increased $ 664 million compared to 2016 due to the increase in Encana’s capital program for 2017. Capital expenditures in the Core Assets totaled $ 1,729 million, representing 96 percent of total capital expenditures, and increased $ 635 million compared to 2016, primarily in Permian ($ 372 million), Eagle Ford ($ 93 million) and Montney ($ 205 million). Capital expenditures exceeded cash from operating activities by $ 746 million and the difference was funded using cash on hand and proceeds from divestitures.
Acquisitions in 2017 were $ 54 million, which primarily included purchases with oil and liquids rich potential.
Divestitures in 2017 were $ 736 million, which primarily included the sale of the Piceance natural gas assets in northwestern Colorado, comprising approximately 550,000 net acres of leasehold and 3,100 operated wells. Divestitures also included the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana and the sale of certain properties that did not complement Encana’s existing portfolio of assets.
2016
Net cash used in investing activities in 2016 was $29 million primarily due to capital expenditures and acquisitions, partially offset by proceeds from divestitures. Capital expenditures in 2016 decreased $1,100 million compared to 2015 due to a reduced capital program and cost savings initiatives implemented in 2016. Capital expenditures in the Core Assets totaled $1,094 million, representing 97 percent of total capital expenditures, and decreased $756 million compared to 2015, primarily in Eagle Ford ($359 million), Permian ($287 million) and Duvernay ($92 million).
65
Capital expenditures exceeded cash from operating activities by $507 million and the difference was funded using proceeds from divestitures.
Acquisitions in 2016 were $210 million, which primarily included $135 million for the purchase of natural gas gathering and water handling assets in Piceance located in Colorado. Acquisitions in 2016 also included the purchase of land and property in Eagle Ford with oil and liquids rich potential.
Divestitures in 2016 were $1,262 million, which primarily included the following:
|
|
• |
Proceeds of approximately $633 million, after closing and other adjustments, for the sale of the DJ Basin assets located in northern Colorado, comprising approximately 51,000 net acres; |
|
|
• |
Proceeds of approximately C$600 million ($455 million), after closing adjustments, for the sale of the Gordondale assets which included approximately 54,200 net acres of land and associated infrastructure in Montney located in northwestern Alberta; and |
|
|
• |
Proceeds of approximately $135 million from the sale of certain natural gas leasehold interests in Piceance located in Colorado. |
Net cash used in financing activities over the past three years has been impacted by Encana’s strategy to enhance liquidity, strengthen its balance sheet and return value to shareholders through the purchase of common shares under a NCIB. The Company has paid dividends each of the past three years.
2018 versus 2017
Net cash used in financing activities in 2018 increased $257 million from 2017. The change was primarily due to the purchase of common shares under a NCIB in 2018 ($250 million) as discussed below.
2017 versus 2016
Net cash used in financing activities in 2017 increased $101 million from 2016. The change was primarily due to the issuance of common shares in 2016 ($ 1,129 million), partially offset by a net repayment of revolving long-term debt ($650 million) and a repayment of long-term debt ($400 million) in 2016.
The transactions affecting the changes in financing activities are discussed in more detail below.
2018 and 2017
Encana’s long-term debt, including the current portion of $500 million which is due May 2019, totaled $4,198 million at December 31, 2018 (2017 - $4,197 million). As at December 31, 2018, over 73 percent of the Company’s debt is not due until 2030 and beyond.
The Company continues to have full access to the Credit Facilities, which remain committed through July 2022. The Credit Facilities provide financial flexibility and allow the Company to fund its operations, development activities or capital program. At December 31, 2018, Encana had no outstanding balance under the Credit Facilities and $147 million in undrawn letters of credit issued in the normal course of business primarily as collateral security, to support future abandonment liabilities and for transportation arrangements.
Encana renewed its Canadian shelf prospectus in August 2018 and has access to a U.S. shelf registration statement filed in 2017, whereby the Company may issue from time to time, debt securities, common shares, Class A preferred shares, subscription receipts, warrants, units, share purchase contracts and share purchase units in Canada and/or the U.S. At December 31, 2018, $6.0 billion remained accessible under the Canadian shelf prospectus. The ability to issue securities under the Canadian shelf prospectus or U.S. shelf registration statement is dependent upon market conditions.
66
In March 2016, the Company completed tender offers (collectively, the “Tender Offers”) for certain of the Company’s outstanding senior notes (collectively, the “Notes”) and accepted for purchase $489 million aggregate principal amount of Notes. The Company paid an aggregate amount of $406 million, including accrued and unpaid interest of $6 million and an early tender premium of $14 million, which resulted in the recognition of a net gain on the early debt retirement of $89 million, before tax. The Company used cash on hand and borrowings under the Credit Facilities to fund the Tender Offers.
On September 23, 2016, Encana completed a public offering (the “2016 Share Offering”) of 107,000,000 common shares of Encana at a price of $9.35 per common share for gross proceeds of approximately $1.0 billion ($981 million of net cash proceeds). On October 4, 2016, an over-allotment option granted to the underwriters (the “Over-Allotment Option”) to purchase up to an additional 16,050,000 common shares at a price of $9.35 per common share was exercised in full for additional gross proceeds of approximately $150 million, bringing the aggregate gross proceeds to approximately $1.15 billion ($1.13 billion of net cash proceeds). During the third quarter of 2016, Encana used a portion of the net proceeds from the 2016 Share Offering and divestitures to repay indebtedness under the Credit Facilities. Further information on the 2016 Share Offering can be found in Note 16 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Dividends
Encana pays quarterly dividends to shareholders at the discretion of the Board of Directors.
|
($ millions, except as indicated) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend Payments |
|
$ |
57 |
|
|
$ |
58 |
|
|
$ |
52 |
|
|
Dividend Payments ($/share) |
|
|
0.06 |
|
|
|
0.06 |
|
|
|
0.06 |
|
On February 27, 2019, the Board of Directors declared a dividend of $0.01875 per common share payable on March 29, 2019 to common shareholders of record as of March 15, 2019. Common shares issued in conjunction with the Newfield acquisition are eligible to receive the dividend declared on February 27, 2019.
The dividends paid in 2018 included $1 million (2017 - $1 million; 2016 - $1 million) in common shares issued in lieu of cash dividends under Encana’s Dividend Reinvestment Plan (“DRIP”). On February 28, 2019, the Company announced the suspension of its DRIP effective immediately.
Normal Course Issuer Bid
On February 13, 2019, the Company confirmed it will proceed with its previously announced plans to spend up to $1.25 billion to purchase common shares, for cancellation, subject to the receipt of regulatory approvals. On February 27, 2019, the Company announced that the TSX accepted its notice of intention to commence a NCIB beginning March 4, 2019 and ending March 3, 2020.
On February 26, 2018, Encana received approval from the TSX to commence a NCIB that enabled the Company to purchase, for cancellation, up to 35 million common shares over a 12-month period from February 28, 2018 to February 27, 2019. Under this NCIB program, the Company used cash on hand to purchase approximately 20.7 million common shares for total consideration of approximately $250 million in 2018. For additional information on the Company’s 2018 NCIB program, refer to Note 16 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
The Company may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. Encana’s material off-balance sheet arrangements include transportation and processing agreements, drilling rig commitments, and building leases, as outlined in the Contractual Obligations table below, as well as undrawn letters of credit, all of which are customary agreements in the oil and gas industry. Other than the items discussed above, there are no other transactions, arrangements, or relationships with unconsolidated entities or persons that are reasonably likely to materially affect the Company’s liquidity or the availability of, or requirements for, capital resources.
67
Contractual obligations arising from long-term debt, capital leases, risk management liabilities, asset retirement obligations and The Bow office building are recognized on the Company’s Consolidated Balance Sheet. The following table outlines the Company’s undiscounted obligations and commitments at December 31, 2018:
|
|
|
Expected Future Payments |
|
|||||||||||||||||||
|
($ millions) |
|
2019 |
|
|
|
2020-2021 |
|
|
2022-2023 |
|
|
|
Thereafter |
|
|
Total |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt |
|
$ |
500 |
|
|
|
$ |
600 |
|
|
$ |
- |
|
|
|
$ |
3,111 |
|
|
$ |
4,211 |
|
|
Interest Payments on Long-Term Debt |
|
|
251 |
|
|
|
|
469 |
|
|
|
422 |
|
|
|
|
2,335 |
|
|
|
3,477 |
|
|
Capital Leases |
|
|
84 |
|
|
|
|
172 |
|
|
|
12 |
|
|
|
|
27 |
|
|
|
295 |
|
|
Interest Payments on Capital Leases |
|
|
15 |
|
|
|
|
14 |
|
|
|
4 |
|
|
|
|
3 |
|
|
|
36 |
|
|
Risk Management Liabilities |
|
|
26 |
|
|
|
|
22 |
|
|
|
- |
|
|
|
|
- |
|
|
|
48 |
|
|
Asset Retirement Obligation |
|
|
91 |
|
|
|
|
197 |
|
|
|
56 |
|
|
|
|
1,027 |
|
|
|
1,371 |
|
|
The Bow Office Building |
|
|
11 |
|
|
|
|
27 |
|
|
|
32 |
|
|
|
|
437 |
|
|
|
507 |
|
|
Interest Payments on The Bow Office Building |
|
|
59 |
|
|
|
|
116 |
|
|
|
113 |
|
|
|
|
681 |
|
|
|
969 |
|
|
Obligations |
|
|
1,037 |
|
|
|
|
1,617 |
|
|
|
639 |
|
|
|
|
7,621 |
|
|
|
10,914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
|
685 |
|
|
|
|
1,259 |
|
|
|
1,008 |
|
|
|
|
2,220 |
|
|
|
5,172 |
|
|
Drilling and Field Services |
|
|
128 |
|
|
|
|
44 |
|
|
|
- |
|
|
|
|
- |
|
|
|
172 |
|
|
Building Leases |
|
|
17 |
|
|
|
|
32 |
|
|
|
31 |
|
|
|
|
35 |
|
|
|
115 |
|
|
Commitments |
|
|
830 |
|
|
|
|
1,335 |
|
|
|
1,039 |
|
|
|
|
2,255 |
|
|
|
5,459 |
|
|
Total Contractual Obligations |
|
$ |
1,867 |
|
|
|
$ |
2,952 |
|
|
$ |
1,678 |
|
|
|
$ |
9,876 |
|
|
$ |
16,373 |
|
|
The Bow Office Building Sublease Recoveries |
|
$ |
(35 |
) |
|
|
$ |
(70 |
) |
|
$ |
(71 |
) |
|
|
$ |
(550 |
) |
|
$ |
(726 |
) |
Interest Payments on Long-Term Debt, Capital Leases and The Bow Office Building represent scheduled cash payments on the respective obligations. Further information can be found in Notes 13 and 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Capital Leases relates to an office building and the obligation related to the Deep Panuke Production Field Centre. Further information can be found in Note 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Risk Management Liabilities represents Encana’s net liability position with counterparties. Further information can be found in Note 23 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Asset Retirement Obligation represents estimated costs arising from the obligation to fund the disposal of long-lived assets upon their abandonment. The majority of Encana’s asset retirement obligations relate to the plugging of wells and related abandonment of oil and gas properties including an offshore production platform, processing plants and land or seabed restoration. Revisions to estimated retirement obligations can result from changes in regulatory requirements, changes in retirement cost estimates, revisions to estimated inflation rates and estimated timing of abandonment. Further information can be found in Note 15 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
The Bow Office Building relates to the 25-year lease agreement with a third-party developer that commenced in 2012. Encana has recognized the accumulated construction costs for The Bow office building as an asset with a related liability. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized. Encana has subleased approximately 50 percent of The Bow office space under the lease agreement. The Bow Office Building Sublease Recoveries in the table above include the amounts expected to be recovered from the sublease. Further information can be found in Note 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Transportation and Processing commitments relate to contractual obligations for capacity rights with third-party pipelines and processing facilities. Drilling and Field Services commitments represent minimum future expenditures for drilling, well servicing and equipment commitment rights. Significant development commitments with joint venture partners are partially satisfied by Commitments included in the table above. Building Leases consist of various building leases used in Encana’s daily operations.
68
Further to the commitments disclosed above, Encana also has various obligations that become payable if certain events occur including variable interests arising from gathering and compression agreements and guarantees on transportation commitments resulting from completed property divestitures as described in Notes 18, 23 and 25, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
In addition, Encana has purchase orders for the purchase of inventory and other goods and services, which typically represent authorization to purchase rather than binding agreements. Encana also has obligations to fund its defined benefit pension and other post-employment benefit plans, as well as unrecognized tax benefits where the settlement is not expected within the next 12 months as described in Notes 21 and 6, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Encana may have potential exposures related to previously divested properties where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser becomes the subject of a proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, Encana could be required to perform such actions under applicable federal laws and regulations. While the Company believes that the risk of such event occurring is low, the Company could be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
Contingencies
For information on contingencies, refer to Note 25 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
69
Accounting Polici es and Estimates
Critical Accounting Estimates
The preparation of financial statements in accordance with U.S. GAAP requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. For a discussion of the Company’s significant accounting policies refer to Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment. The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to determining Encana’s financial results. Changes in the estimates and assumptions discussed below could materially affect the amount or timing of the financial results of the Company.
70
71
Recent Accounting Pronouncements
For recently issued accounting policies, refer to Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
72
Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. These measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Non-GAAP Cash Flow, Non-GAAP Cash Flow Margin, Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA. Management’s use of these measures is discussed further below.
Non-GAAP Cash Flow and Non-GAAP Cash Flow Margin
Non-GAAP Cash Flow is a non-GAAP measure defined as cash from (used in) operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and current tax on sale of assets.
Non-GAAP Cash Flow Margin is a non-GAAP measure defined as Non-GAAP Cash Flow per BOE of production.
Management believes these measures are useful to the Company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, and are an indication of the Company’s ability to generate cash to finance capital programs, to service debt and to meet other financial obligations. These measures are used, along with other measures, in the calculation of certain performance targets for the Company’s management and employees.
|
($ millions, except as indicated) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
$ |
2,300 |
|
|
$ |
1,050 |
|
|
$ |
625 |
|
|
(Add back) deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in other assets and liabilities |
|
|
(60 |
) |
|
|
(40 |
) |
|
|
(26 |
) |
|
Net change in non-cash working capital |
|
|
245 |
|
|
|
(253 |
) |
|
|
(187 |
) |
|
Current tax on sale of assets |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Non-GAAP Cash Flow |
|
$ |
2,115 |
|
|
$ |
1,343 |
|
|
$ |
838 |
|
|
Production Volumes (MMBOE) |
|
|
131.8 |
|
|
|
114.3 |
|
|
|
129.1 |
|
|
Non-GAAP Cash Flow Margin ($/BOE) |
|
$ |
16.05 |
|
|
$ |
11.75 |
|
|
$ |
6.49 |
|
Debt to Adjusted Capitalization
Debt to Adjusted Capitalization is a non-GAAP measure which adjusts capitalization for historical ceiling test impairments that were recorded as at December 31, 2011. Management monitors Debt to Adjusted Capitalization as a proxy for Encana’s financial covenant under the Credit Facilities which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders’ equity and an equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP.
|
($ millions, except as indicated) |
|
December 31, 2018 |
|
|
December 31, 2017 |
|
|
December 31, 2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt, including current portion |
|
$ |
4,198 |
|
|
$ |
4,197 |
|
|
$ |
4,198 |
|
|
Total Shareholders’ Equity |
|
|
7,447 |
|
|
|
6,728 |
|
|
|
6,126 |
|
|
Equity Adjustment for Impairments at December 31, 2011 |
|
|
7,746 |
|
|
|
7,746 |
|
|
|
7,746 |
|
|
Adjusted Capitalization |
|
$ |
19,391 |
|
|
$ |
18,671 |
|
|
$ |
18,070 |
|
|
Debt to Adjusted Capitalization |
|
22% |
|
|
22% |
|
|
23% |
|
|||
73
Net Debt to Adjusted EBITDA is a non-GAAP measure whereby Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents and Adjusted EBITDA is defined as trailing 12-month net earnings (loss) before income taxes, DD&A, impairments, accretion of asset retirement obligation, interest, unrealized gains/losses on risk management, foreign exchange gains/losses, gains/losses on divestitures and other gains/losses.
Management believes this measure is useful to the Company and its investors as a measure of financial leverage and the Company’s ability to service its debt and other financial obligations. This measure is used, along with other measures, in the calculation of certain financial performance targets for the Company’s management and employees.
|
($ millions, except as indicated) |
|
December 31, 2018 |
|
|
December 31, 2017 |
|
|
December 31, 2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt, including current portion |
|
$ |
4,198 |
|
|
$ |
4,197 |
|
|
$ |
4,198 |
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
1,058 |
|
|
|
719 |
|
|
|
834 |
|
|
Net Debt |
|
|
3,140 |
|
|
|
3,478 |
|
|
|
3,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
1,069 |
|
|
|
827 |
|
|
|
(944 |
) |
|
Add back (deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
1,272 |
|
|
|
833 |
|
|
|
859 |
|
|
Impairments |
|
|
- |
|
|
|
- |
|
|
|
1,396 |
|
|
Accretion of asset retirement obligation |
|
|
32 |
|
|
|
37 |
|
|
|
51 |
|
|
Interest |
|
|
351 |
|
|
|
363 |
|
|
|
397 |
|
|
Unrealized (gains) losses on risk management |
|
|
(519 |
) |
|
|
(442 |
) |
|
|
614 |
|
|
Foreign exchange (gain) loss, net |
|
|
168 |
|
|
|
(279 |
) |
|
|
(210 |
) |
|
(Gain) loss on divestitures, net |
|
|
(5 |
) |
|
|
(404 |
) |
|
|
(390 |
) |
|
Other (gains) losses, net |
|
|
17 |
|
|
|
(42 |
) |
|
|
(58 |
) |
|
Income tax expense (recovery) |
|
|
94 |
|
|
|
603 |
|
|
|
(676 |
) |
|
Adjusted EBITDA |
|
$ |
2,479 |
|
|
$ |
1,496 |
|
|
$ |
1,039 |
|
|
Net Debt to Adjusted EBITDA (times) |
|
|
1.3 |
|
|
|
2.3 |
|
|
|
3.2 |
|
74
Item 7A : Quantitative and Qualitat ive Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Encana’s potential exposure to market risks. The term “market risk” refers to the Company’s risk of loss arising from adverse changes in oil, NGL and natural gas prices, foreign currency exchange rates and interest rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. The Company’s policy is to not use derivative financial instruments for speculative purposes.
COMMODITY PRICE RISK
Commodity price risk arises from the effect fluctuations in future commodity prices, including oil, NGLs and natural gas, may have on future revenues, expenses and cash flows. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to the Company’s natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable as discussed in Item 1A. “Risk Factors” of this Annual Report on Form 10-K. To partially mitigate exposure to commodity price risk, the Company may enter into various derivative financial instruments including futures, forwards, swaps, options and costless collars. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors and may vary from time to time. Both exchange traded and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 23 under Item 8 of this Annual Report on Form 10-K.
The table below summarizes the sensitivity of the fair value of the Company’s risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:
|
|
|
December 31, 2018 |
|
|||||
|
|
|
10% Price |
|
|
10% Price |
|
||
|
(US$ millions) |
|
Increase |
|
|
Decrease |
|
||
|
Crude oil price |
|
$ |
(81 |
) |
|
$ |
71 |
|
|
NGL price |
|
|
(17 |
) |
|
|
17 |
|
|
Natural gas price |
|
|
(35 |
) |
|
|
32 |
|
FOREIGN EXCHANGE RISK
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. As Encana operates in Canada and the United States, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Company’s reported results. Although Encana’s financial results are consolidated in Canadian dollars, the Company reports its results in U.S. dollars as most of its revenues are closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies.
75
The table below summarizes selected foreign exchange impacts on Encana’s financial results when compared to the same periods in the prior years.
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||||||||||||||||
|
|
$ millions |
|
|
$/BOE |
|
|
$ millions |
|
|
$/BOE |
|
|
$ millions |
|
|
$/BOE |
|
|||||||||||
|
Increase (Decrease) in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
$ |
(3 |
) |
|
|
|
|
|
|
$ |
7 |
|
|
|
|
|
|
|
|
$ |
(25 |
) |
|
|
|
|
|
|
Transportation and Processing Expense (1) |
|
|
(1 |
) |
|
$ |
(0.01 |
) |
|
|
|
11 |
|
|
|
$ |
0.10 |
|
|
|
|
(25 |
) |
|
|
$ |
(0.19 |
) |
|
Operating Expense (1) |
|
|
- |
|
|
|
- |
|
|
|
|
4 |
|
|
|
|
0.03 |
|
|
|
|
(5 |
) |
|
|
|
(0.04 |
) |
|
Administrative Expense |
|
|
(2 |
) |
|
|
(0.01 |
) |
|
|
|
4 |
|
|
|
|
0.03 |
|
|
|
|
(7 |
) |
|
|
|
(0.05 |
) |
|
Depreciation, Depletion and Amortization (1) |
|
|
- |
|
|
|
- |
|
|
|
|
5 |
|
|
|
|
0.05 |
|
|
|
|
(13 |
) |
|
|
|
(0.10 |
) |
|
(1) |
Reflects upstream operations. |
Foreign exchange gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated and settled, and primarily include:
|
|
• |
U.S. dollar denominated financing debt issued from Canada |
|
|
• |
U.S. dollar denominated risk management assets and liabilities held in Canada |
|
|
• |
U.S. dollar denominated cash and short-term investments held in Canada |
|
|
• |
Foreign denominated intercompany loans |
To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at December 31, 2018, Encana has entered into $1.0 billion notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7516 to C$1, which mature monthly throughout 2019.
As at December 31, 2018, Encana had $4.2 billion in U.S. dollar long-term debt and $240 million in U.S. dollar capital lease obligations issued from Canada that were subject to foreign exchange exposure.
The table below summarizes the sensitivity to foreign exchange rate fluctuations, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact from Canadian to U.S. foreign currency exchange rate changes. Fluctuations in foreign currency exchange rates could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:
|
|
|
December 31, 2018 |
|
|||||
|
(US$ millions) |
|
10% Rate Increase |
|
|
10% Rate Decrease |
|
||
|
Foreign currency exchange |
|
$ |
(67 |
) |
|
$ |
82 |
|
INTEREST RATE RISK
Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company’s financial assets or liabilities. The Company may partially mitigate its exposure to interest rate changes by holding a mix of both fixed and floating rate debt and may also enter into interest rate derivatives to partially mitigate effects of fluctuations in market interest rates.
As at December 31, 2018, the Company had no floating rate debt and there were no interest rate derivatives outstanding.
76
Item 8: Financial Statements a nd Supplementary Data
Management Report
Management’s Responsibility for Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Encana Corporation (the “Company”) are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in United States dollars in accordance with generally accepted accounting principles in the United States and include certain estimates that reflect Management’s best judgments.
The Company’s Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee, which has a written mandate that complies with the requirements of Canadian and United States securities legislation and the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets at least on a quarterly basis.
Management’s Assessment of Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. The internal control system was designed to provide reasonable assurance to the Company’s Management regarding the preparation and presentation of the Consolidated Financial Statements.
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.
Management has assessed the design and effectiveness of the Company’s internal control over financial reporting as at December 31, 2018. In making its assessment, Management has used the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Based on our evaluation, Management has concluded that the Company’s internal control over financial reporting was effective as at that date.
PricewaterhouseCoopers LLP, an independent firm of chartered professional accountants, was appointed by a vote of shareholders at the Company’s last annual meeting to audit and provide independent opinions on both the Consolidated Financial Statements and the Company’s internal control over financial reporting as at December 31, 2018, as stated in their Auditor’s Report. PricewaterhouseCoopers LLP has provided such opinions.
|
/s/ Douglas J. Suttles Douglas J. Suttles President & Chief Executive Officer
February 28, 2019 |
/s/ Sherri A. Brillon Sherri A. Brillon Executive Vice-President & Chief Financial Officer |
77
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Encana Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying Consolidated Balance Sheet of Encana Corporation and its subsidiaries, (together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of Earnings, Comprehensive Income, Changes in Shareholders’ Equity and Cash Flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and their results of operations and their cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America (“US GAAP”). Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
78
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 28, 2019
We have served as the auditor of the Company or its predecessor since 1958.
79
Consolidated Statement of Earnings
|
For the years ended December 31 (US$ millions, except per share amounts) |
|
2018 |
|
|
2017 (1) |
|
|
2016 (1) |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
(Notes 2, 3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Product and service revenues |
|
|
|
$ |
5,457 |
|
|
$ |
3,892 |
|
|
$ |
3,122 |
|
|
Gains (losses) on risk management, net |
|
(Note 23) |
|
|
415 |
|
|
|
482 |
|
|
|
(275 |
) |
|
Sublease revenues |
|
|
|
|
67 |
|
|
|
69 |
|
|
|
71 |
|
|
Total Revenues |
|
|
|
|
5,939 |
|
|
|
4,443 |
|
|
|
2,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
(Note 2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production, mineral and other taxes |
|
|
|
|
147 |
|
|
|
112 |
|
|
|
99 |
|
|
Transportation and processing |
|
(Note 23) |
|
|
1,083 |
|
|
|
845 |
|
|
|
901 |
|
|
Operating |
|
(Notes 20, 21) |
|
|
454 |
|
|
|
506 |
|
|
|
598 |
|
|
Purchased product |
|
|
|
|
1,100 |
|
|
|
788 |
|
|
|
586 |
|
|
Depreciation, depletion and amortization |
|
|
|
|
1,272 |
|
|
|
833 |
|
|
|
859 |
|
|
Impairments |
|
(Note 9) |
|
|
- |
|
|
- |
|
|
|
1,396 |
|
|
|
Accretion of asset retirement obligation |
|
(Note 15) |
|
|
32 |
|
|
|
37 |
|
|
|
51 |
|
|
Administrative |
|
(Notes 19, 20, 21) |
|
|
157 |
|
|
|
254 |
|
|
|
309 |
|
|
Total Operating Expenses |
|
|
|
|
4,245 |
|
|
|
3,375 |
|
|
|
4,799 |
|
|
Operating Income (Loss) |
|
|
|
|
1,694 |
|
|
|
1,068 |
|
|
|
(1,881 |
) |
|
Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
(Notes 4, 13) |
|
|
351 |
|
|
|
363 |
|
|
|
397 |
|
|
Foreign exchange (gain) loss, net |
|
(Notes 5, 23) |
|
|
168 |
|
|
|
(279 |
) |
|
|
(210 |
) |
|
(Gain) loss on divestitures, net |
|
(Note 8) |
|
|
(5 |
) |
|
|
(404 |
) |
|
|
(390 |
) |
|
Other (gains) losses, net |
|
(Note 21) |
|
|
17 |
|
|
|
(42 |
) |
|
|
(58 |
) |
|
Total Other (Income) Expenses |
|
|
|
|
531 |
|
|
|
(362 |
) |
|
|
(261 |
) |
|
Net Earnings (Loss) Before Income Tax |
|
|
|
|
1,163 |
|
|
|
1,430 |
|
|
|
(1,620 |
) |
|
Income tax expense (recovery) |
|
(Note 6) |
|
|
94 |
|
|
|
603 |
|
|
|
(676 |
) |
|
Net Earnings (Loss) |
|
|
|
$ |
1,069 |
|
|
$ |
827 |
|
|
$ |
(944 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
|
(Note 16) |
|
$ |
1.11 |
|
|
$ |
0.85 |
|
|
$ |
(1.07 |
) |
|
Weighted Average Common Shares Outstanding (millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
|
(Note 16) |
|
|
959.8 |
|
|
|
973.1 |
|
|
|
882.6 |
|
|
(1) |
2017 and 2016 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”. |
Consolidated Statement of Comprehensive Income
|
For the years ended December 31 (US$ millions) |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
$ |
1,069 |
|
|
$ |
827 |
|
|
$ |
(944 |
) |
|
Other Comprehensive Income (Loss), Net of Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
|
(Note 17) |
|
|
(53 |
) |
|
|
(171 |
) |
|
|
(183 |
) |
|
Pension and other post-employment benefit plans |
|
(Notes 17, 21) |
|
|
9 |
|
|
|
3 |
|
|
|
3 |
|
|
Other Comprehensive Income (Loss) |
|
|
|
|
(44 |
) |
|
|
(168 |
) |
|
|
(180 |
) |
|
Comprehensive Income (Loss) |
|
|
|
$ |
1,025 |
|
|
$ |
659 |
|
|
$ |
(1,124 |
) |
See accompanying Notes to Consolidated Financial Statements
80
|
As at December 31 (US$ millions) |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
$ |
1,058 |
|
|
$ |
719 |
|
|
Accounts receivable and accrued revenues |
|
(Note 7) |
|
|
789 |
|
|
|
774 |
|
|
Risk management |
|
(Notes 22, 23) |
|
|
554 |
|
|
|
205 |
|
|
Income tax receivable |
|
|
|
|
275 |
|
|
|
573 |
|
|
|
|
|
|
|
2,676 |
|
|
|
2,271 |
|
|
Property, Plant and Equipment, at cost: |
|
(Note 9) |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, based on full cost accounting |
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
|
|
41,241 |
|
|
|
40,228 |
|
|
Unproved properties |
|
|
|
|
3,730 |
|
|
|
4,480 |
|
|
Other |
|
|
|
|
2,122 |
|
|
|
2,302 |
|
|
Property, plant and equipment |
|
|
|
|
47,093 |
|
|
|
47,010 |
|
|
Less: Accumulated depreciation, depletion and amortization |
|
|
|
|
(38,121 |
) |
|
|
(38,056 |
) |
|
Property, plant and equipment, net |
|
(Note 2) |
|
|
8,972 |
|
|
|
8,954 |
|
|
Other Assets |
|
(Note 10) |
|
|
147 |
|
|
|
144 |
|
|
Risk Management |
|
(Notes 22, 23) |
|
|
161 |
|
|
|
246 |
|
|
Deferred Income Taxes |
|
(Note 6) |
|
|
835 |
|
|
|
1,043 |
|
|
Goodwill |
(Notes 2, 8, 11) |
|
|
2,553 |
|
|
|
2,609 |
|
|
|
|
|
(Note 2) |
|
$ |
15,344 |
|
|
$ |
15,267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
(Note 12) |
|
$ |
1,490 |
|
|
$ |
1,415 |
|
|
Income tax payable |
|
|
|
|
1 |
|
|
|
7 |
|
|
Risk management |
|
(Notes 22, 23) |
|
|
25 |
|
|
|
236 |
|
|
Current portion of long-term debt |
|
(Note 13) |
|
|
500 |
|
|
|
- |
|
|
|
|
|
|
|
2,016 |
|
|
|
1,658 |
|
|
Long-Term Debt |
|
(Note 13) |
|
|
3,698 |
|
|
|
4,197 |
|
|
Other Liabilities and Provisions |
|
(Note 14) |
|
|
1,769 |
|
|
|
2,167 |
|
|
Risk Management |
|
(Notes 22, 23) |
|
|
22 |
|
|
|
13 |
|
|
Asset Retirement Obligation |
|
(Note 15) |
|
|
365 |
|
|
|
470 |
|
|
Deferred Income Taxes |
|
(Note 6) |
|
|
27 |
|
|
|
34 |
|
|
|
|
|
|
|
7,897 |
|
|
|
8,539 |
|
|
Commitments and Contingencies |
|
(Note 25) |
|
|
|
|
|
|
|
|
|
Shareholders’ Equity |
|
|
|
|
|
|
|
|
|
|
|
Share capital - authorized unlimited common shares 2018 issued and outstanding: 952.5 million shares (2017: 973.1 million shares) |
(Note 16) |
|
|
4,656 |
|
|
|
4,757 |
|
|
|
Paid in surplus |
|
|
|
|
1,358 |
|
|
|
1,358 |
|
|
Retained earnings (Accumulated deficit) |
|
|
|
|
435 |
|
|
|
(429 |
) |
|
Accumulated other comprehensive income |
|
(Note 17) |
|
|
998 |
|
|
|
1,042 |
|
|
Total Shareholders’ Equity |
|
|
|
|
7,447 |
|
|
|
6,728 |
|
|
|
|
|
|
$ |
15,344 |
|
|
$ |
15,267 |
|
See accompanying Notes to Consolidated Financial Statements
|
Approved by the Board of Directors |
|
|
|
|
|
|
|
|
/s/ Clayton H. Woitas |
/s/ Bruce G. Waterman |
|
Clayton H. Woitas |
Bruce G. Waterman |
|
Director |
Director |
81
Consolidated Statement of Changes in Shareholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained |
|
|
Accumulated |
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings |
|
|
Other |
|
|
Total |
|
|||
|
|
|
|
|
Share |
|
|
Paid in |
|
|
(Accumulated |
|
|
Comprehensive |
|
|
Shareholders’ |
|
|||||
|
For the year ended December 31, 2018 (US$ millions) |
|
|
|
Capital |
|
|
Surplus |
|
|
Deficit) |
|
|
Income |
|
|
Equity |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2017 |
|
|
|
$ |
4,757 |
|
|
$ |
1,358 |
|
|
$ |
(429 |
) |
|
$ |
1,042 |
|
|
$ |
6,728 |
|
|
Net Earnings (Loss) |
|
|
|
- |
|
|
- |
|
|
|
1,069 |
|
|
- |
|
|
|
1,069 |
|
|||
|
Dividends on Common Shares ($0.06 per share) |
|
(Note 16) |
|
- |
|
|
- |
|
|
|
(57 |
) |
|
- |
|
|
|
(57 |
) |
|||
|
Common Shares Purchased under Normal Course Issuer Bid |
|
(Note 16) |
|
|
(102 |
) |
|
- |
|
|
|
(148 |
) |
|
- |
|
|
|
(250 |
) |
||
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
(Note 16) |
|
|
1 |
|
|
- |
|
|
- |
|
|
- |
|
|
|
1 |
|
|||
|
Other Comprehensive Income (Loss) |
|
(Note 17) |
|
- |
|
|
- |
|
|
- |
|
|
|
(44 |
) |
|
|
(44 |
) |
|||
|
Balance, December 31, 2018 |
|
|
|
$ |
4,656 |
|
|
$ |
1,358 |
|
|
$ |
435 |
|
|
$ |
998 |
|
|
$ |
7,447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained |
|
|
Accumulated |
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings |
|
|
Other |
|
|
Total |
|
|||
|
|
|
|
|
Share |
|
|
Paid in |
|
|
(Accumulated |
|
|
Comprehensive |
|
|
Shareholders’ |
|
|||||
|
For the year ended December 31, 2017 (US$ millions) |
|
|
|
Capital |
|
|
Surplus |
|
|
Deficit) |
|
|
Income |
|
|
Equity |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2016 |
|
|
|
$ |
4,756 |
|
|
$ |
1,358 |
|
|
$ |
(1,198 |
) |
|
$ |
1,210 |
|
|
$ |
6,126 |
|
|
Net Earnings (Loss) |
|
|
|
- |
|
|
- |
|
|
|
827 |
|
|
- |
|
|
|
827 |
|
|||
|
Dividends on Common Shares ($0.06 per share) |
|
(Note 16) |
|
- |
|
|
- |
|
|
|
(58 |
) |
|
- |
|
|
|
(58 |
) |
|||
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
(Note 16) |
|
|
1 |
|
|
- |
|
|
- |
|
|
- |
|
|
|
1 |
|
|||
|
Other Comprehensive Income (Loss) |
|
(Note 17) |
|
- |
|
|
- |
|
|
- |
|
|
|
(168 |
) |
|
|
(168 |
) |
|||
|
Balance, December 31, 2017 |
|
|
|
$ |
4,757 |
|
|
$ |
1,358 |
|
|
$ |
(429 |
) |
|
$ |
1,042 |
|
|
$ |
6,728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained |
|
|
Accumulated |
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings |
|
|
Other |
|
|
Total |
|
|||
|
|
|
|
|
Share |
|
|
Paid in |
|
|
(Accumulated |
|
|
Comprehensive |
|
|
Shareholders’ |
|
|||||
|
For the year ended December 31, 2016 (US$ millions) |
|
|
|
Capital |
|
|
Surplus |
|
|
Deficit) |
|
|
Income |
|
|
Equity |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2015 |
|
|
|
$ |
3,621 |
|
|
$ |
1,358 |
|
|
$ |
(202 |
) |
|
$ |
1,390 |
|
|
$ |
6,167 |
|
|
Net Earnings (Loss) |
|
|
|
- |
|
|
- |
|
|
|
(944 |
) |
|
- |
|
|
|
(944 |
) |
|||
|
Dividends on Common Shares ($0.06 per share) |
|
(Note 16) |
|
- |
|
|
- |
|
|
|
(52 |
) |
|
- |
|
|
|
(52 |
) |
|||
|
Common Shares Issued |
|
(Note 16) |
|
|
1,134 |
|
|
- |
|
|
- |
|
|
- |
|
|
|
1,134 |
|
|||
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
(Note 16) |
|
|
1 |
|
|
- |
|
|
- |
|
|
- |
|
|
|
1 |
|
|||
|
Other Comprehensive Income (Loss) |
|
(Note 17) |
|
- |
|
|
- |
|
|
- |
|
|
|
(180 |
) |
|
|
(180 |
) |
|||
|
Balance, December 31, 2016 |
|
|
|
$ |
4,756 |
|
|
$ |
1,358 |
|
|
$ |
(1,198 |
) |
|
$ |
1,210 |
|
|
$ |
6,126 |
|
See accompanying Notes to Consolidated Financial Statements
82
Consolidated Statement of Cash Flows
|
For the years ended December 31 (US$ millions) |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
|
|
$ |
1,069 |
|
|
$ |
827 |
|
|
$ |
(944 |
) |
|
Depreciation, depletion and amortization |
|
|
|
|
1,272 |
|
|
|
833 |
|
|
|
859 |
|
|
Impairments |
|
(Note 9) |
|
|
- |
|
|
- |
|
|
|
1,396 |
|
|
|
Accretion of asset retirement obligation |
|
(Note 15) |
|
|
32 |
|
|
|
37 |
|
|
|
51 |
|
|
Deferred income taxes |
|
(Note 6) |
|
|
149 |
|
|
|
666 |
|
|
|
(598 |
) |
|
Unrealized (gain) loss on risk management |
|
(Note 23) |
|
|
(519 |
) |
|
|
(442 |
) |
|
|
614 |
|
|
Unrealized foreign exchange (gain) loss |
|
(Note 5) |
|
|
233 |
|
|
|
(291 |
) |
|
|
(140 |
) |
|
Foreign exchange on settlements |
|
(Note 5) |
|
|
(46 |
) |
|
|
24 |
|
|
|
(68 |
) |
|
(Gain) loss on divestitures, net |
|
(Note 8) |
|
|
(5 |
) |
|
|
(404 |
) |
|
|
(390 |
) |
|
Other |
|
|
|
|
(70 |
) |
|
|
93 |
|
|
|
58 |
|
|
Net change in other assets and liabilities |
|
|
|
|
(60 |
) |
|
|
(40 |
) |
|
|
(26 |
) |
|
Net change in non-cash working capital |
|
(Note 24) |
|
|
245 |
|
|
|
(253 |
) |
|
|
(187 |
) |
|
Cash From (Used in) Operating Activities |
|
|
|
|
2,300 |
|
|
|
1,050 |
|
|
|
625 |
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
(Note 2) |
|
|
(1,975 |
) |
|
|
(1,796 |
) |
|
|
(1,132 |
) |
|
Acquisitions |
|
(Note 8) |
|
|
(17 |
) |
|
|
(54 |
) |
|
|
(210 |
) |
|
Proceeds from divestitures |
|
(Note 8) |
|
|
493 |
|
|
|
736 |
|
|
|
1,262 |
|
|
Net change in investments and other |
|
|
|
|
(56 |
) |
|
|
77 |
|
|
|
51 |
|
|
Cash From (Used in) Investing Activities |
|
|
|
|
(1,555 |
) |
|
|
(1,037 |
) |
|
|
(29 |
) |
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net issuance (repayment) of revolving long-term debt |
|
(Note 13) |
|
|
- |
|
|
- |
|
|
|
(650 |
) |
|
|
Repayment of long-term debt |
|
(Note 13) |
|
|
- |
|
|
- |
|
|
|
(400 |
) |
|
|
Issuance of common shares, net of offering costs |
|
(Note 16) |
|
|
- |
|
|
- |
|
|
|
1,129 |
|
|
|
Purchase of common shares |
|
(Note 16) |
|
|
(250 |
) |
|
- |
|
|
- |
|
||
|
Dividends on common shares |
|
(Note 16) |
|
|
(56 |
) |
|
|
(57 |
) |
|
|
(51 |
) |
|
Capital lease payments and other financing arrangements |
|
(Note 14) |
|
|
(90 |
) |
|
|
(82 |
) |
|
|
(66 |
) |
|
Cash From (Used in) Financing Activities |
|
|
|
|
(396 |
) |
|
|
(139 |
) |
|
|
(38 |
) |
|
Foreign Exchange Gain (Loss) on Cash and Cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalents Held in Foreign Currency |
|
|
|
|
(10 |
) |
|
|
11 |
|
|
|
5 |
|
|
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
|
339 |
|
|
|
(115 |
) |
|
|
563 |
|
|
Cash and Cash Equivalents, Beginning of Year |
|
|
|
|
719 |
|
|
|
834 |
|
|
|
271 |
|
|
Cash and Cash Equivalents, End of Year |
|
|
|
$ |
1,058 |
|
|
$ |
719 |
|
|
$ |
834 |
|
|
Cash, End of Year |
|
|
|
$ |
52 |
|
|
$ |
51 |
|
|
$ |
78 |
|
|
Cash Equivalents, End of Year |
|
|
|
|
1,006 |
|
|
|
668 |
|
|
|
756 |
|
|
Cash and Cash Equivalents, End of Year |
|
|
|
$ |
1,058 |
|
|
$ |
719 |
|
|
$ |
834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary Cash Flow Information |
|
(Note 24) |
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements
83
|
A) |
NATURE OF OPERATIONS |
Encana is in the business of the exploration for, the development of, and the production and marketing of oil, NGLs and natural gas.
|
B) |
BASIS OF PRESENTATION |
The Consolidated Financial Statements include the accounts of Encana and are presented in conformity with U.S. GAAP and the rules and regulations of the SEC.
In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are expressed in U.S. dollars. Encana’s financial results are consolidated in Canadian dollars; however, the Company has adopted the U.S. dollar as its reporting currency to facilitate a more direct comparison to other North American oil and gas companies. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.
|
C) |
PRINCIPLES OF CONSOLIDATION |
The Consolidated Financial Statements include the accounts of Encana and entities in which it holds a controlling interest. All intercompany balances and transactions are eliminated on consolidation. Undivided interests in oil and natural gas exploration and production joint ventures and partnerships are consolidated on a proportionate basis. Investments in non-controlled entities over which Encana has the ability to exercise significant influence are accounted for using the equity method.
|
D) |
FOREIGN CURRENCY TRANSLATION |
Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings. Foreign currency revenues and expenses are translated at the rates of exchange in effect at the time of the transaction.
Assets and liabilities of foreign operations are translated at period end exchange rates, while the related revenues and expenses are translated using average rates during the period. Translation gains and losses relating to the foreign operations are included in accumulated other comprehensive income (“AOCI”). Recognition of Encana’s accumulated translation gains and losses into net earnings occurs upon complete or substantially complete liquidation of the Company’s investment in the foreign operation.
For financial statement presentation, assets and liabilities are translated into the reporting currency at period end exchange rates, while revenues and expenses are translated using average rates over the period. Gains and losses relating to the financial statement translation are included in AOCI.
|
E) |
USE OF ESTIMATES |
Preparation of the Consolidated Financial Statements in conformity with U.S. GAAP requires Management to make informed estimates and assumptions and use judgments that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future events occur.
84
Significant items subject to estimates and assumptions are:
|
|
• |
Estimates of proved reserves used for depletion and ceiling test impairment calculations |
|
|
• |
Estimated fair value of long-term assets used for impairment calculations |
|
|
• |
Fair value of reporting units used for the assessment of goodwill |
|
|
• |
Estimates of future taxable earnings used to assess the realizable value of deferred tax assets |
|
|
• |
Fair value of asset retirement costs and related obligations |
|
|
• |
Fair value of derivative instruments |
|
|
• |
Fair value attributed to assets acquired and liabilities assumed in business combinations |
|
|
• |
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate |
|
|
• |
Accruals for long-term performance-based compensation arrangements, including whether or not the performance criteria will be met and measurement of the ultimate payout amount |
|
|
• |
Recognized values of pension assets and obligations, as well as the pension costs charged to net earnings, depend on certain actuarial and economic assumptions |
|
|
• |
Accruals for legal claims, environmental risks and exposures |
|
F) |
REVENUES FROM CONTRACTS WITH CUSTOMERS |
Revenues from contracts with customers associated with Encana’s oil, NGLs and natural gas and third party processing and gathering are recognized when control of the good or service is transferred to the customer, and title or risk of loss transfers to the customer. Transaction prices are determined at inception of the contract and allocated to the performance obligations identified. Variable consideration is estimated and included in the transaction price, unless the variable consideration is constrained.
For product sales, the performance obligations are satisfied at a point in time when the product is delivered to the customer and control is transferred. Payment from the customer is due when the product is delivered to the custody point. Revenues for product sales are presented on an after-royalties basis. For arrangements to gather and process natural gas for third parties, performance obligations are satisfied over time as the service is provided to the customer. Payment from the customer is due when the customer receives the benefit of the service and the product is delivered to the custody point or plant tailgate. Revenues associated with services provided where Encana acts as agent are recorded on a net basis.
|
G) |
PRODUCTION, MINERAL AND OTHER TAXES |
Costs paid by Encana for taxes based on production or revenues from oil, NGLs and natural gas are recognized when the product is produced. Costs paid by Encana for taxes on the valuation of upstream assets and reserves are recognized when incurred.
|
H) |
TRANSPORTATION AND PROCESSING |
Costs paid by Encana for the transportation and processing of oil, NGLs and natural gas are recognized when the product is delivered and the services made available or provided.
|
I) |
OPERATING |
Operating costs paid by Encana, net of amounts capitalized, for oil and natural gas properties in which the Company has a working interest.
|
J) |
EMPLOYEE BENEFIT PLANS |
The Company sponsors defined contribution and defined benefit plans, providing pension and other post-employment benefits to its employees in Canada and the U.S. As of January 1, 2003, the defined benefit pension plan was closed to new entrants.
Pension expense for the defined contribution pension plan is recorded as the benefits are earned by the employees covered by the plans. Encana accrues for its obligations under its employee defined benefit plans, net of plan assets. The cost of defined benefit pensions and other post-employment benefits is actuarially determined using the
85
projected benefit method based on length of service and reflects Management’s best estimate of salary escalation, mortality rates, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on historical and projected rates of return for assets in the investment plan portfolio. The actual return is based on the fair value of plan assets. The projected benefit obligation is discounted using the market interest rate on high-quality corporate debt instruments as at the measurement date.
Defined benefit pension plan expenses include the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of adjustments arising from pension plan amendments, the amortization of net prior service costs, and the amortization of the excess of the net actuarial gains or losses over 10 percent of the greater of the benefit obligation and the fair value of plan assets. Amortization is on a straight-line basis over a period covering the expected average remaining service lives of employees covered by the plans. Actuarial gains and losses related to the change in the over-funded or under-funded status of the defined benefit pension plan and other post-employment benefit plans are recognized in other comprehensive income.
|
K) |
INCOME TAXES |
Encana follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the enacted income tax rates and laws expected to apply when the assets are realized and liabilities are settled. Current income taxes are measured at the amount expected to be recoverable from or payable to the taxing authorities based on the income tax rates and laws enacted at the end of the reporting period. The effect of a change in the enacted tax rates or laws is recognized in net earnings in the period of enactment. Income taxes are recognized in net earnings except to the extent that they relate to items recognized directly in shareholders’ equity, in which case the income taxes are recognized directly in shareholders’ equity.
Deferred income tax assets are assessed routinely for realizability. If it is more likely than not that deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets. Encana considers available positive and negative evidence when assessing the realizability of deferred tax assets including historic and expected future taxable earnings, available tax planning strategies and carry forward periods. The assumptions used in determining expected future taxable earnings are consistent with those used in the goodwill impairment assessment.
Encana recognizes the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. A recognized tax position is initially and subsequently measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon settlement with a taxing authority. Liabilities for unrecognized tax benefits that are not expected to be settled within the next 12 months are included in other liabilities and provisions. Interest related to unrecognized tax benefits is recognized in interest expense.
|
L) |
EARNINGS PER SHARE AMOUNTS |
Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per common share amounts are calculated giving effect to the potential dilution that would occur if stock options were exercised or other contracts to issue common shares were exercised, fully vested, or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to repurchase common shares at the average market price.
|
M) |
CASH AND CASH EQUIVALENTS |
Cash and cash equivalents include cash on hand and short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased. Outstanding disbursements issued in excess of applicable bank account balances are excluded from cash and cash equivalents and are recorded in accounts payable and accrued liabilities.
86
UPSTREAM
Encana uses the full cost method of accounting for its acquisition, exploration and development activities. Accordingly, all costs directly associated with the acquisition of, the exploration for, and the development of oil, NGLs and natural gas reserves, including costs of undeveloped leaseholds, dry holes and related equipment, are capitalized on a country-by-country cost centre basis. Capitalized costs exclude costs relating to production, general overhead or similar activities.
Capitalized costs accumulated within each cost centre are depleted using the unit-of-production method based on proved reserves. Depletion is calculated using the capitalized costs, including estimated retirement costs, plus the undiscounted future expenditures, based on current costs, to be incurred in developing proved reserves.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed separately for impairment on a quarterly basis. Costs that have been impaired are included in the costs subject to depletion within the full cost pool.
Under the full cost method of accounting, the carrying amount of Encana’s oil and natural gas properties within each country cost centre is subject to a ceiling test at the end of each quarter. A ceiling test impairment is recognized in net earnings when the carrying amount of a country cost centre exceeds the country cost centre ceiling. The carrying amount of a cost centre includes capitalized costs of proved oil and natural gas properties, net of accumulated depletion and the related deferred income taxes.
The cost centre ceiling is the sum of the estimated after-tax future net cash flows from proved reserves, using the 12-month average trailing prices and unescalated future development and production costs, discounted at 10 percent, plus unproved property costs. The 12-month average trailing price is calculated as the average of the price on the first day of each month within the trailing 12-month period. Any excess of the carrying amount over the calculated ceiling amount is recognized as an impairment in net earnings.
Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of a gain or loss unless the deduction significantly alters the relationship between capitalized costs and proved reserves in the cost centre, in which case a gain or loss is recognized in net earnings. Generally, a gain or loss on a divestiture would be recognized when 25 percent or more of the Company’s proved reserves quantities are sold in a particular country cost centre. For divestitures that result in the recognition of a gain or loss on the sale and constitute a business, goodwill is allocated to the divestiture.
CORPORATE
Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 25 years. Costs associated with The Bow office building are carried at cost and depreciated on a straight-line basis over the 60-year estimated life of the building. Assets under construction are not subject to depreciation until put into use. Land is carried at cost.
|
O) |
CAPITALIZATION OF COSTS |
Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Interest on borrowings associated with major development projects is capitalized during the construction phase.
|
P) |
BUSINESS COMBINATIONS |
Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at fair value at the date of acquisition. Deferred taxes are recognized for any differences between the fair value of net assets acquired and the related tax bases. Any excess of the purchase price over the fair value of the net
87
assets acquired is recognized as goodwill. Any deficiency of the purchase price below the fair value of the net assets acquired is recorded as a gain in net earnings. Associated transaction costs are expensed when incurred.
|
Q) |
GOODWILL |
Goodwill represents the excess of purchase price over fair value of net assets acquired and is assessed for impairment at least annually at December 31. Goodwill and all other assets and liabilities are allocated to reporting units, which are Encana’s country cost centres. To assess impairment, the carrying amount of each reporting unit is determined and compared to the fair value of the reporting unit. If the carrying amount of the reporting unit, including goodwill, is higher than its related fair value then goodwill is written down to the reporting unit’s implied fair value of goodwill. The implied fair value of goodwill is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit as if the reporting entity had been acquired in a business combination. Any excess of the carrying value of goodwill over the implied fair value of goodwill is recognized as an impairment and charged to net earnings. Subsequent measurement of goodwill is at cost less any accumulated impairments.
|
R) |
IMPAIRMENT OF LONG-TERM ASSETS |
The carrying value of long-term assets, excluding goodwill and upstream assets included in property, plant and equipment, is assessed for impairment when indicators suggest that the carrying value of an asset or asset group may not be recoverable. If the carrying amount exceeds the sum of the undiscounted cash flows expected to result from the continued use and eventual disposition of the asset or asset group, an impairment is recognized for the excess of the carrying amount over its estimated fair value.
|
S) |
ASSET RETIREMENT OBLIGATION |
Asset retirement obligations are those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, an offshore production platform, processing plants, and restoring land or seabed at the end of oil and gas production operations. The asset retirement obligation is initially measured at its fair value and recorded as a liability with an offsetting retirement cost that is capitalized as part of the related long-lived asset on the Consolidated Balance Sheet. The estimated fair value is measured by reference to the expected future cash flows required to satisfy the obligation, discounted at the Company’s credit-adjusted risk-free rate. Changes in the estimated obligation resulting from revisions to estimated timing or amount of future cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost.
Amortization of asset retirement costs are included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset retirement obligations resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.
Actual expenditures incurred are charged against the accumulated asset retirement obligation.
|
T) |
STOCK-BASED COMPENSATION |
Stock-based compensation arrangements are accounted for at fair value. Fair values are determined using observable share prices and/or pricing models such as the Black-Scholes-Merton option-pricing model. For equity-settled stock-based compensation plans, fair values are determined at the grant date and are recognized over the vesting period as compensation costs with a corresponding credit to shareholders’ equity. For cash-settled stock-based compensation plans, fair values are determined at each reporting date and periodic changes are recognized as compensation costs, with a corresponding change to liabilities. Compensation costs are recognized over the vesting period using the accelerated attribution method for awards with a graded vesting feature. Forfeitures are estimated based on the Company’s historical turnover rates.
|
U) |
LEASES |
Leases entered into for the use of an asset are classified as either capital or operating leases. Capital leases transfer to the Company substantially all of the risks and benefits incidental to ownership of the leased item. Capital leases are capitalized upon commencement of the lease term at the lower of the fair value of the leased asset or the present value of the minimum lease payments. Capitalized leased assets are amortized over the estimated useful life of the
88
asset if the lease arrangement contains a bargain purchase option or ownership of the leased asset transfers at the end of the lease term. Otherwise, the leased assets are amortized over the lease term. Amortization of capitalized leased assets is included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. All other leases are classified as operating leases and the payments are recognized on a straight-line basis over the lease term. Subleases relate to office and building leases. Sublease rental revenues are recognized straight-line over the lease term.
|
V) |
FAIR VALUE MEASUREMENTS |
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques include the market, income and cost approach. The market approach uses information generated by market transactions involving identical or comparable assets or liabilities; the income approach converts estimated future amounts to a present value; the cost approach is based on the amount that currently would be required to replace an asset.
Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair value hierarchy are as follows:
|
|
• |
Level 1 - Inputs represent quoted prices in active markets for identical assets or liabilities, such as exchange-traded commodity derivatives. |
|
|
• |
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quoted market prices for similar assets or liabilities in active markets or other market corroborated inputs. |
|
|
• |
Level 3 - Inputs that are not observable from objective sources, such as forward prices supported by little or no market activity or internally developed estimates of future cash flows used in a present value model. |
In determining fair value, the Company utilizes the most observable inputs available. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair value measurement is characterized based on the lowest level of input that is significant to the fair value measurement.
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated Balance Sheet approximates fair value. The fair value of long-term debt is disclosed in Note 13. Fair value information related to pension plan assets is included in Note 21. Recurring fair value measurements are performed for risk management assets and liabilities and other derivative contracts as discussed in Note 22.
Certain non-financial assets and liabilities are initially measured at fair value, such as asset retirement obligations and assets and liabilities acquired in business combinations or certain non-monetary exchange transactions.
|
W) |
RISK MANAGEMENT ASSETS AND LIABILITIES |
Risk management assets and liabilities are derivative financial instruments used by Encana to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.
Derivative instruments that do not qualify for the normal purchases and sales exemption are measured at fair value with changes in fair value recognized in net earnings. The fair values recorded in the Consolidated Balance Sheet reflect netting the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Realized gains or losses from financial derivatives related to oil, NGLs and natural gas commodity prices are recognized in revenues as the contracts are settled. Realized gains or losses from financial derivatives related to power commodity prices are recognized in transportation and processing expense as the related power contracts are settled. Realized gains or losses from foreign currency exchange swaps are recognized in foreign exchange (gain) loss as the contracts are settled.
Realized gains or losses recognized from other derivative contracts related to certain payment obligations are presented in revenues as the obligations are settled. Unrealized gains and losses recognized are presented in
89
revenues, transportation and processing expense and foreign exchange (gain) loss accordingly, at the end of each respective reporting period based on the changes in fair value of the contracts.
|
X) |
COMMITMENTS AND CONTINGENCIES |
Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.
|
Y) |
RECENT ACCOUNTING PRONOUNCEMENTS |
Changes in Accounting Policies and Practices
On January 1, 2018, Encana adopted the following ASUs issued by the FASB, which have not had a material impact on the Company's Consolidated Financial Statements:
|
|
• |
ASU 2014-09, “Revenue from Contracts with Customers” under Topic 606. The new standard replaces Topic 605, “Revenue Recognition” as well as other industry-specific guidance within the Accounting Standards Codification. Topic 606 is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the company expects to be entitled to in exchange for those goods or services. The standard has been applied using the modified retrospective approach to contracts which were not completed as of January 1, 2018 and did not have a material impact on the Company’s Consolidated Financial Statements, other than enhancing disclosures related to the disaggregation of revenues from contracts with customers and performance obligations. The disclosures required under Topic 606 are included in Note 3, Revenues from Contracts with Customers. |
|
|
• |
ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendment requires the service cost component to be presented with the related employee compensation costs, while the other components of net benefit costs are required to be presented separately from the service cost component and outside the subtotal of income from operations. In addition, the amendment allows only the service cost to be eligible for capitalization. The amendment has been applied retrospectively for the presentation of net periodic pension costs and net periodic postretirement benefit cost, whereas prospective adoption has been applied to the capitalization of the service cost component. |
New Standards Issued Not Yet Adopted
|
|
• |
As of January 1, 2019, Encana will be required to adopt ASU 2016-02, “Leases” under Topic 842, which will replace Topic 840 “Leases”. The new standard will require lessees to recognize right-of-use assets and related lease liabilities for all leases, including leases classified as operating leases, on the Consolidated Balance Sheet. However, Topic 842 provides a short-term lease exemption which does not require a right-of-use asset and lease liability to be recognized on the Consolidated Balance Sheet when the lease term is 12 months or less, including any renewal periods which are reasonably certain to be exercised. Encana intends to elect the short-term lease exemption. Topic 842 also expands disclosures related to the amount, timing and uncertainty of cash flows arising from leases. |
In July 2018, FASB issued ASU 2018-11, “Targeted Improvements”, providing entities the option to apply Topic 842 at the adoption date recognizing a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption, while the comparative periods presented would continue to be in accordance with Topic 840. Encana intends to elect this optional transition method, as well as certain practical expedients permitted under Topic 842, which will allow the Company to retain the classification of leases assessed under Topic 840 that commenced prior to adoption. Encana also intends to adopt the transitional practical expedient provided under ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842” issued by FASB in January 2018. This amendment applies to land easements that existed or expired prior to adoption of Topic 842 and were not previously accounted for as leases under Topic 840. The expedient provides prospective application of Topic 842 to all new or modified land easements upon adoption of the new standard.
90
While Encana continues to assess all the effects of adopting Topic 842, the significant impacts relate to i) the recognition of right-of-use assets and corresponding liabilities for the Company’s operating leases which include drilling rigs, compressors, generators, supply vessels, various equipment utilized in the development and production of oil and natural gas, camps, office s and buildings; ii) the derecognition of The Bow office building sale leaseback transaction which did not qualify for sale recognition under Topic 840; and iii) providing new disclosures related to the Company’s leasing activities. On adoption of Topic 842, Encana expects to recognize new right-of-use assets and liabilities from operating leases ranging from $110 million to $130 million on the Company’s Consolidated Balance Sheet. In addition, The Bow office building will be accounted for as an operating lease under Topic 842, with the right-of-use asset and corresponding lease liability measured at the present value of the remaining lease payments, while the previously recorded asset and financing liability resulting from the failed sale leaseback transaction that was measured under Topic 840 will be derecognized. The net difference arising from the derecognition of the asset and financing liability associated with the change in the accounting for The Bow office building will be recognized through opening retained earnings on January 1, 2019. The impact from the change in the accounting for The Bow office building is expected to result in a decrease to the Consolidated Balance Sheet ranging from $260 million to $280 million. The Company does not expect Topic 842 to have a material impact on the Consolidated Statements of Earnings or Cash Flows.
|
|
• |
As of January 1, 2019, Encana will be required to adopt ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments allow for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (“U.S. Tax Reform”). Amendments can be applied either in the period of adoption or retrospectively to each period in which the effect of the rate change from U.S. Tax Reform is recognized. While Encana has other post-employment benefit plans which were affected by U.S. Tax Reform, the impact is not material to the Company’s Consolidated Financial Statements. As a result, the Company does not intend to take the election provided in the amendment. |
|
|
• |
As of January 1, 2020, Encana will be required to adopt ASU 2017-04, “Simplifying the Test for Goodwill Impairment”. The amendment eliminates the second step of the goodwill impairment test which requires the Company to measure the impairment based on the excess amount of the carrying value of the reporting unit’s goodwill over the implied fair value of its goodwill. Under this amendment, the goodwill impairment will be measured based on the excess amount of the reporting unit’s carrying value over its respective fair value. The amendment will be applied prospectively at the date of adoption. Encana is currently in the early stages of reviewing the amendment, but does not expect the amendment to have a material impact on the Company’s Consolidated Financial Statements. |
91
Encana’s reportable segments are determined based on the Company’s operations and geographic locations as follows:
|
• |
Canadian Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the Canadian cost centre. |
|
• |
USA Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the U.S. cost centre. |
|
• |
Market Optimization is primarily responsible for the sale of the Company’s proprietary production. These results are reported in the Canadian and USA Operations. Market optimization activities include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market Optimization sells substantially all of the Company’s upstream production to third party customers. Transactions between segments are based on market values and are eliminated on consolidation. |
Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate. Corporate and Other also includes amounts related to sublease rentals.
92
Segment Information
|
|
|
Canadian Operations |
|
|
USA Operations |
|
|
Market Optimization |
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For the years ended December 31 |
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2018 |
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2017 (1) |
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2016 (1) |
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2018 |
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2017 (1) |
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2016 (1) |
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2018 |
|
|
2017 (1) |
|
|
2016 (1) |
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Revenues |
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|
|
|
|
Product and service revenues |
|
$ |
1,721 |
|
|
$ |
1,169 |
|
|
$ |
960 |
|
|
$ |
2,512 |
|
|
$ |
1,860 |
|
|
$ |
1,515 |
|
|
$ |
1,224 |
|
|
$ |
863 |
|
|
$ |
647 |
|
|
Gains (losses) on risk management, net |
|
|
100 |
|
|
|
22 |
|
|
|
107 |
|
|
|
(199 |
) |
|
|
18 |
|
|
|
255 |
|
|
|
(5 |
) |
|
|
- |
|
|
|
(1 |
) |
|
Sublease revenues |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
|
Total Revenues |
|
|
1,821 |
|
|
|
1,191 |
|
|
|
1,067 |
|
|
|
2,313 |
|
|
|
1,878 |
|
|
|
1,770 |
|
|
|
1,219 |
|
|
|
863 |
|
|
|
646 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production, mineral and other taxes |
|
|
16 |
|
|
|
20 |
|
|
|
23 |
|
|
|
131 |
|
|
|
92 |
|
|
|
76 |
|
|
|
- |
|
|
- |
|
|
- |
|
||
|
Transportation and processing |
|
|
828 |
|
|
|
578 |
|
|
|
576 |
|
|
|
124 |
|
|
|
164 |
|
|
|
260 |
|
|
|
131 |
|
|
|
103 |
|
|
|
87 |
|
|
Operating |
|
|
118 |
|
|
|
122 |
|
|
|
152 |
|
|
|
305 |
|
|
|
331 |
|
|
|
394 |
|
|
|
16 |
|
|
|
35 |
|
|
|
35 |
|
|
Purchased product |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,100 |
|
|
|
788 |
|
|
|
586 |
|
|
Depreciation, depletion and amortization |
|
|
361 |
|
|
|
236 |
|
|
|
260 |
|
|
|
860 |
|
|
|
530 |
|
|
|
523 |
|
|
|
1 |
|
|
|
1 |
|
|
- |
|
|
|
Impairments |
|
|
- |
|
|
|
- |
|
|
|
493 |
|
|
|
- |
|
|
|
- |
|
|
|
903 |
|
|
|
- |
|
|
- |
|
|
- |
|
||
|
Total Operating Expenses |
|
|
1,323 |
|
|
|
956 |
|
|
|
1,504 |
|
|
|
1,420 |
|
|
|
1,117 |
|
|
|
2,156 |
|
|
|
1,248 |
|
|
|
927 |
|
|
|
708 |
|
|
Operating Income (Loss) |
|
$ |
498 |
|
|
$ |
235 |
|
|
$ |
(437 |
) |
|
$ |
893 |
|
|
$ |
761 |
|
|
$ |
(386 |
) |
|
$ |
(29 |
) |
|
$ |
(64 |
) |
|
$ |
(62 |
) |
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
Consolidated |
|
||||||||||||||||||
|
|
|
|
|
|
|
|
|
2018 |
|
|
2017 (1) |
|
|
2016 (1) |
|
|
2018 |
|
|
2017 (1) |
|
|
2016 (1) |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product and service revenues |
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
5,457 |
|
|
$ |
3,892 |
|
|
$ |
3,122 |
|
|
Gains (losses) on risk management, net |
|
|
|
|
|
|
|
|
519 |
|
|
|
442 |
|
|
|
(636 |
) |
|
|
415 |
|
|
|
482 |
|
|
|
(275 |
) |
|
Sublease revenues |
|
|
|
|
|
|
|
|
67 |
|
|
|
69 |
|
|
|
71 |
|
|
|
67 |
|
|
|
69 |
|
|
|
71 |
|
|
Total Revenues |
|
|
|
|
|
|
|
|
586 |
|
|
|
511 |
|
|
|
(565 |
) |
|
|
5,939 |
|
|
|
4,443 |
|
|
|
2,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production, mineral and other taxes |
|
|
|
|
|
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
147 |
|
|
|
112 |
|
|
|
99 |
|
||
|
Transportation and processing |
|
|
|
|
|
|
|
|
- |
|
|
- |
|
|
|
(22 |
) |
|
|
1,083 |
|
|
|
845 |
|
|
|
901 |
|
|
|
Operating |
|
|
|
|
|
|
|
|
15 |
|
|
|
18 |
|
|
|
17 |
|
|
|
454 |
|
|
|
506 |
|
|
|
598 |
|
|
Purchased product |
|
|
|
|
|
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
1,100 |
|
|
|
788 |
|
|
|
586 |
|
||
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
50 |
|
|
|
66 |
|
|
|
76 |
|
|
|
1,272 |
|
|
|
833 |
|
|
|
859 |
|
|
Impairments |
|
|
|
|
|
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
- |
|
|
|
1,396 |
|
|||
|
Accretion of asset retirement obligation |
|
|
|
|
|
|
|
|
32 |
|
|
|
37 |
|
|
|
51 |
|
|
|
32 |
|
|
|
37 |
|
|
|
51 |
|
|
Administrative |
|
|
|
|
|
|
|
|
157 |
|
|
|
254 |
|
|
|
309 |
|
|
|
157 |
|
|
|
254 |
|
|
|
309 |
|
|
Total Operating Expenses |
|
|
|
|
|
|
|
|
254 |
|
|
|
375 |
|
|
|
431 |
|
|
|
4,245 |
|
|
|
3,375 |
|
|
|
4,799 |
|
|
Operating Income (Loss) |
|
|
|
|
|
|
|
$ |
332 |
|
|
$ |
136 |
|
|
$ |
(996 |
) |
|
|
1,694 |
|
|
|
1,068 |
|
|
|
(1,881 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
351 |
|
|
|
363 |
|
|
|
397 |
|
|
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168 |
|
|
|
(279 |
) |
|
|
(210 |
) |
|
(Gain) loss on divestitures, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
(404 |
) |
|
|
(390 |
) |
|
Other (gains) losses, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
(42 |
) |
|
|
(58 |
) |
|
Total Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
531 |
|
|
|
(362 |
) |
|
|
(261 |
) |
|
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,163 |
|
|
|
1,430 |
|
|
|
(1,620 |
) |
|
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94 |
|
|
|
603 |
|
|
|
(676 |
) |
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,069 |
|
|
$ |
827 |
|
|
$ |
(944 |
) |
|
(1) |
2017 and 2016 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”. |
93
|
|
|
Market Optimization |
|
|||||||||||||||||||||||||||||||||
|
|
|
Marketing Sales |
|
|
Upstream Eliminations |
|
|
Total |
|
|||||||||||||||||||||||||||
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
5,724 |
|
|
$ |
3,939 |
|
|
$ |
3,304 |
|
|
$ |
(4,505 |
) |
|
$ |
(3,076 |
) |
|
$ |
(2,658 |
) |
|
$ |
1,219 |
|
|
$ |
863 |
|
|
$ |
646 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
457 |
|
|
|
291 |
|
|
|
279 |
|
|
|
(326 |
) |
|
|
(188 |
) |
|
|
(192 |
) |
|
|
131 |
|
|
|
103 |
|
|
|
87 |
|
|
Operating |
|
|
16 |
|
|
|
35 |
|
|
|
35 |
|
|
- |
|
|
- |
|
|
- |
|
|
|
16 |
|
|
|
35 |
|
|
|
35 |
|
|||
|
Purchased product |
|
|
5,279 |
|
|
|
3,676 |
|
|
|
3,052 |
|
|
|
(4,179 |
) |
|
|
(2,888 |
) |
|
|
(2,466 |
) |
|
|
1,100 |
|
|
|
788 |
|
|
|
586 |
|
|
Depreciation, depletion and amortization |
|
|
1 |
|
|
|
1 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
|
- |
|
|||||
|
Operating Income (Loss) |
|
$ |
(29 |
) |
|
$ |
(64 |
) |
|
$ |
(62 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(29 |
) |
|
$ |
(64 |
) |
|
$ |
(62 |
) |
Revenues by Geographic Region
|
|
|
Canada |
|
|
United States |
|
|
Total |
|
|||||||||||||||||||||||||||
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
7 |
|
|
$ |
7 |
|
|
$ |
26 |
|
|
$ |
2,093 |
|
|
$ |
1,360 |
|
|
$ |
1,015 |
|
|
$ |
2,100 |
|
|
$ |
1,367 |
|
|
$ |
1,041 |
|
|
NGLs |
|
|
863 |
|
|
|
481 |
|
|
|
298 |
|
|
|
289 |
|
|
|
193 |
|
|
|
126 |
|
|
|
1,152 |
|
|
|
674 |
|
|
|
424 |
|
|
Natural gas |
|
|
826 |
|
|
|
662 |
|
|
|
628 |
|
|
|
126 |
|
|
|
296 |
|
|
|
350 |
|
|
|
952 |
|
|
|
958 |
|
|
|
978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenues (1) |
|
|
262 |
|
|
|
189 |
|
|
|
166 |
|
|
|
1,058 |
|
|
|
773 |
|
|
|
584 |
|
|
|
1,320 |
|
|
|
962 |
|
|
|
750 |
|
|
Gains (losses) on risk management, net |
|
|
199 |
|
|
|
522 |
|
|
|
(151 |
) |
|
|
216 |
|
|
|
(40 |
) |
|
|
(124 |
) |
|
|
415 |
|
|
|
482 |
|
|
|
(275 |
) |
|
Total Revenues |
|
$ |
2,157 |
|
|
$ |
1,861 |
|
|
$ |
967 |
|
|
$ |
3,782 |
|
|
$ |
2,582 |
|
|
$ |
1,951 |
|
|
$ |
5,939 |
|
|
$ |
4,443 |
|
|
$ |
2,918 |
|
|
(1) |
Includes market optimization and other revenues such as purchased product sold to third parties, sublease revenues and gathering and processing services provided to third parties. |
Export Sales
Sales of oil, NGLs and natural gas produced or purchased in Canada delivered to customers outside of Canada were $135 million for the year ended December 31, 2018 (2017 - $64 million; 2016 - $50 million).
Major Customers
In connection with the marketing and sale of Encana’s own and purchased oil, NGLs and natural gas for the year ended December 31, 2018, the Company had one customer which individually accounted for more than 10 percent of Encana’s product revenues. Sales to this customer, which has an investment grade credit rating, totaled approximately $752 million which comprised $250 million in Canada and $502 million in the United States (2017 - two customers with sales of approximately $709 million and $412 million, respectively; 2016 - two customers with sales of approximately $434 million and $343 million, respectively).
94
Capital Expenditures by Segment
|
For the years ended December 31 |
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
$ |
632 |
|
|
$ |
426 |
|
|
$ |
256 |
|
|
USA Operations |
|
|
|
|
|
|
|
|
1,332 |
|
|
|
1,358 |
|
|
|
873 |
|
|
Market Optimization |
|
|
|
|
|
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
|
Corporate & Other |
|
|
|
|
|
|
|
|
11 |
|
|
|
11 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
$ |
1,975 |
|
|
$ |
1,796 |
|
|
$ |
1,132 |
|
Goodwill, Property, Plant and Equipment and Total Assets by Segment
|
|
|
Goodwill |
|
|
Property, Plant and Equipment |
|
|
Total Assets |
|
|||||||||||||||
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
640 |
|
|
$ |
696 |
|
|
$ |
999 |
|
|
$ |
862 |
|
|
$ |
1,852 |
|
|
$ |
1,908 |
|
|
USA Operations |
|
|
1,913 |
|
|
|
1,913 |
|
|
|
6,591 |
|
|
|
6,555 |
|
|
|
9,104 |
|
|
|
9,301 |
|
|
Market Optimization |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
2 |
|
|
|
295 |
|
|
|
152 |
|
|
Corporate & Other |
|
|
- |
|
|
|
- |
|
|
|
1,381 |
|
|
|
1,535 |
|
|
|
4,093 |
|
|
|
3,906 |
|
|
|
|
$ |
2,553 |
|
|
$ |
2,609 |
|
|
$ |
8,972 |
|
|
$ |
8,954 |
|
|
$ |
15,344 |
|
|
$ |
15,267 |
|
Goodwill, Property, Plant and Equipment and Total Assets by Geographic Region
|
|
|
Goodwill |
|
|
Property, Plant and Equipment |
|
|
Total Assets |
|
|||||||||||||||
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
640 |
|
|
$ |
696 |
|
|
$ |
2,303 |
|
|
$ |
2,319 |
|
|
$ |
5,211 |
|
|
$ |
5,412 |
|
|
United States |
|
|
1,913 |
|
|
|
1,913 |
|
|
|
6,669 |
|
|
|
6,635 |
|
|
|
10,108 |
|
|
|
9,811 |
|
|
Other Countries |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
25 |
|
|
|
44 |
|
|
|
|
$ |
2,553 |
|
|
$ |
2,609 |
|
|
$ |
8,972 |
|
|
$ |
8,954 |
|
|
$ |
15,344 |
|
|
$ |
15,267 |
|
95
The following table summarizes the Company’s revenues from contracts with customers and other sources of revenues. Encana presents realized and unrealized gains and losses on certain derivative contracts within revenues.
Revenues
|
|
|
Canadian Operations |
|
|
USA Operations |
|
|
Market Optimization |
|
|||||||||||||||||||||||||||
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from Customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
7 |
|
|
$ |
7 |
|
|
$ |
26 |
|
|
$ |
2,099 |
|
|
$ |
1,373 |
|
|
$ |
1,026 |
|
|
$ |
89 |
|
|
$ |
115 |
|
|
$ |
124 |
|
|
NGLs |
|
|
870 |
|
|
|
485 |
|
|
|
300 |
|
|
|
290 |
|
|
|
193 |
|
|
|
128 |
|
|
|
8 |
|
|
|
10 |
|
|
|
36 |
|
|
Natural gas |
|
|
849 |
|
|
|
680 |
|
|
|
641 |
|
|
|
126 |
|
|
|
305 |
|
|
|
362 |
|
|
|
1,109 |
|
|
|
704 |
|
|
|
448 |
|
|
Service revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing |
|
|
6 |
|
|
|
9 |
|
|
|
7 |
|
|
|
4 |
|
|
|
11 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Product and Service Revenues |
|
|
1,732 |
|
|
|
1,181 |
|
|
|
974 |
|
|
|
2,519 |
|
|
|
1,882 |
|
|
|
1,540 |
|
|
|
1,206 |
|
|
|
829 |
|
|
|
608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) on risk management, net (2) |
|
|
100 |
|
|
|
22 |
|
|
|
107 |
|
|
|
(199 |
) |
|
|
18 |
|
|
|
255 |
|
|
|
(5 |
) |
|
|
- |
|
|
|
(1 |
) |
|
Sublease revenues |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Other Revenues |
|
|
100 |
|
|
|
22 |
|
|
|
107 |
|
|
|
(199 |
) |
|
|
18 |
|
|
|
255 |
|
|
|
(5 |
) |
|
|
- |
|
|
|
(1 |
) |
|
Total Revenues |
|
$ |
1,832 |
|
|
$ |
1,203 |
|
|
$ |
1,081 |
|
|
$ |
2,320 |
|
|
$ |
1,900 |
|
|
$ |
1,795 |
|
|
$ |
1,201 |
|
|
$ |
829 |
|
|
$ |
607 |
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
Consolidated |
|
||||||||||||||||||
|
|
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from Customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
2,195 |
|
|
$ |
1,495 |
|
|
$ |
1,176 |
|
|
NGLs |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,168 |
|
|
|
688 |
|
|
|
464 |
|
|
Natural gas |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,084 |
|
|
|
1,689 |
|
|
|
1,451 |
|
|
Service revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10 |
|
|
|
20 |
|
|
|
31 |
|
|
Product and Service Revenues |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,457 |
|
|
|
3,892 |
|
|
|
3,122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) on risk management, net (2) |
|
|
|
|
|
|
|
|
519 |
|
|
|
442 |
|
|
|
(636 |
) |
|
|
415 |
|
|
|
482 |
|
|
|
(275 |
) |
|
Sublease revenues |
|
|
|
|
|
|
|
|
67 |
|
|
|
69 |
|
|
|
71 |
|
|
|
67 |
|
|
|
69 |
|
|
|
71 |
|
|
Other Revenues |
|
|
|
|
|
|
|
|
586 |
|
|
|
511 |
|
|
|
(565 |
) |
|
|
482 |
|
|
|
551 |
|
|
|
(204 |
) |
|
Total Revenues |
|
|
|
|
|
|
|
$ |
586 |
|
|
$ |
511 |
|
|
$ |
(565 |
) |
|
$ |
5,939 |
|
|
$ |
4,443 |
|
|
$ |
2,918 |
|
|
(1) |
Includes revenues from production and revenues of product purchased from third parties, but excludes intercompany marketing fees transacted between the Company’s operating segments. |
|
(2) |
Canadian Operations, USA Operations and Market Optimization include realized gains (losses) on risk management. Corporate & Other includes unrealized gains (losses) on risk management. |
The Company’s revenues from contracts with customers consists of product sales including oil, NGLs and natural gas, as well as the provision of gathering and processing services to third parties. Encana had no contract asset or liability balances during the periods presented. For the year ended December 31, 2018, receivables and accrued revenues from contracts with customers were $662 million (2017 - $676 million).
Encana’s product sales are sold under short-term contracts with terms that are less than one year at either fixed or market index prices or under long-term contracts exceeding one year at market index prices.
The Company’s gathering and processing services are provided on an interruptible basis with transaction prices that are for fixed prices and/or variable consideration. Variable consideration received is related to recovery of plant operating costs or escalation of the fixed price based on a consumer price index. As the service contracts are interruptible, with service provided on an “as available” basis, there are no unsatisfied performance obligations remaining for the year ended December 31, 2018.
96
As at December 31, 2018, all remaining performance obligations are priced at market index prices or are variable volume delivery contracts. As such, the variable consideration is allocated entirely to the wholly unsatisfied performance obligation or promise to deliver units of production, and revenue is recognized at the amount for which the Company has the right to invoice the product delivered. As the period between when the product sales are transferred and Encana receives payments is generally 30 to 60 days, there is no financing element associated with customer contracts. In addition, Encana does not disclose unsatisfied performance obligations for customer contracts with terms less than 12 months.
|
4. |
Interest |
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt |
|
$ |
267 |
|
|
$ |
267 |
|
|
$ |
296 |
|
|
The Bow office building |
|
|
63 |
|
|
|
63 |
|
|
|
62 |
|
|
Capital leases |
|
|
16 |
|
|
|
20 |
|
|
|
24 |
|
|
Other |
|
|
5 |
|
|
|
13 |
|
|
|
15 |
|
|
|
|
$ |
351 |
|
|
$ |
363 |
|
|
$ |
397 |
|
|
5. |
Foreign Exchange (Gain) Loss, Net |
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Foreign Exchange (Gain) Loss on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation of U.S. dollar financing debt issued from Canada |
|
$ |
358 |
|
|
$ |
(243 |
) |
|
$ |
(130 |
) |
|
Translation of U.S. dollar risk management contracts issued from Canada |
|
|
24 |
|
|
|
(44 |
) |
|
|
4 |
|
|
Translation of intercompany notes |
|
|
(149 |
) |
|
|
(4 |
) |
|
|
(14 |
) |
|
|
|
|
233 |
|
|
|
(291 |
) |
|
|
(140 |
) |
|
Foreign Exchange on Settlements of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. dollar financing debt issued from Canada |
|
|
3 |
|
|
|
14 |
|
|
|
(73 |
) |
|
U.S. dollar risk management contracts issued from Canada |
|
|
(10 |
) |
|
|
(15 |
) |
|
|
- |
|
|
Intercompany notes |
|
|
(49 |
) |
|
|
10 |
|
|
|
5 |
|
|
Other Monetary Revaluations |
|
|
(9 |
) |
|
|
3 |
|
|
|
(2 |
) |
|
|
|
$ |
168 |
|
|
$ |
(279 |
) |
|
$ |
(210 |
) |
The unrealized foreign exchange (gain) loss on translation of U.S. dollar financing debt issued from Canada for the year ended December 31, 2017 disclosed in the table above included an out-of-period adjustment in respect of unrealized losses on a foreign-denominated capital lease obligation since December 2013. The cumulative impact recognized within foreign exchange (gain) loss in the Company’s Consolidated Statement of Earnings for the year ended December 31, 2017 was $68 million, before tax ($47 million, after tax). Encana determined that the adjustment was not material to the Consolidated Financial Statements for the year ended December 31, 2017 or any prior periods. Accordingly, comparative periods presented in the Consolidated Financial Statements were not restated.
97
The provision for income taxes is as follows:
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
(62 |
) |
|
$ |
(59 |
) |
|
$ |
(82 |
) |
|
United States |
|
|
4 |
|
|
|
(9 |
) |
|
|
- |
|
|
Other Countries |
|
|
3 |
|
|
|
5 |
|
|
|
4 |
|
|
Total Current Tax Expense (Recovery) |
|
|
(55 |
) |
|
|
(63 |
) |
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
(46 |
) |
|
|
55 |
|
|
|
(163 |
) |
|
United States |
|
|
195 |
|
|
|
611 |
|
|
|
(435 |
) |
|
Other Countries |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Total Deferred Tax Expense (Recovery) |
|
|
149 |
|
|
|
666 |
|
|
|
(598 |
) |
|
Income Tax Expense (Recovery) |
|
$ |
94 |
|
|
$ |
603 |
|
|
$ |
(676 |
) |
During the years ended December 31, 2018, 2017 and 2016, the current income tax recovery was primarily due to the successful resolution of amounts in respect of prior taxation years.
On December 22, 2017, U.S. Tax Reform was signed into law making significant changes to the U.S. tax code, including a reduction of the U.S. federal corporate tax rate from 35 percent to 21 percent. During the year ended December 31, 2017, the deferred tax expense of $666 million included a provisional tax adjustment of $327 million resulting from the re-measurement of the Company’s tax position due to U.S. Tax Reform. The adjustment of $327 million included a $26 million valuation allowance re-measurement with respect to U.S. foreign tax credits and U.S. charitable donations.
During the year ended December 31, 2018, there was no change to the provisional tax adjustment recognized in 2017 resulting from the re-measurement of the Company’s tax position due to a reduction of the U.S. federal corporate tax rate under U.S. Tax Reform. As at December 31, 2018, the Company has completed its assessment of the income tax effects in respect of the provisional adjustment related to U.S. Tax Reform.
During the year ended December 31, 2016, the deferred tax recovery was primarily due to the ceiling test impairments recognized in the Canadian and USA Operations as disclosed in Note 9.
98
The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes:
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
19 |
|
|
$ |
512 |
|
|
$ |
(627 |
) |
|
United States |
|
|
929 |
|
|
|
476 |
|
|
|
(1,522 |
) |
|
Other Countries |
|
|
215 |
|
|
|
442 |
|
|
|
529 |
|
|
Total Net Earnings (Loss) Before Income Tax |
|
|
1,163 |
|
|
|
1,430 |
|
|
|
(1,620 |
) |
|
Canadian Statutory Rate |
|
|
27.0 |
% |
|
|
27.0 |
% |
|
|
27.0 |
% |
|
Expected Income Tax |
|
|
314 |
|
|
|
386 |
|
|
|
(437 |
) |
|
Effect on Taxes Resulting From: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax related to foreign operations |
|
|
(106 |
) |
|
|
(73 |
) |
|
|
(266 |
) |
|
Effect of legislative changes |
|
|
- |
|
|
|
299 |
|
|
|
- |
|
|
Non-taxable capital (gains) losses |
|
|
22 |
|
|
|
(39 |
) |
|
|
(29 |
) |
|
Tax differences on divestitures and transactions |
|
|
- |
|
|
|
77 |
|
|
|
9 |
|
|
Partnership tax allocations in excess of funding |
|
|
(68 |
) |
|
|
(54 |
) |
|
|
(17 |
) |
|
Amounts in respect of prior periods |
|
|
(54 |
) |
|
|
(49 |
) |
|
|
(11 |
) |
|
Change in valuation allowance |
|
|
8 |
|
|
|
54 |
|
|
|
121 |
|
|
Other |
|
|
(22 |
) |
|
|
2 |
|
|
|
(46 |
) |
|
|
|
$ |
94 |
|
|
$ |
603 |
|
|
$ |
(676 |
) |
|
Effective Tax Rate |
|
|
8.1 |
% |
|
|
42.2 |
% |
|
|
41.7 |
% |
The effective tax rate of 8.1 percent for the year ended December 31, 2018 is lower than the Canadian statutory rate of 27 percent primarily due to the impact of foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings, partnership tax allocations in excess of funding and the successful resolution of certain tax items relating to prior taxation years. For the year ended December 31, 2017, the effective tax rate was 42.2 percent, which was higher than the Canadian statutory tax rate of 27 percent primarily due to U.S. Tax Reform, which increased Encana’s effective tax rate by 22.9 percent, and the successful resolution of certain tax items relating to prior taxation years. The effective tax rate for the year ended December 31, 2016 exceeded the Canadian statutory tax rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings.
The net deferred income tax asset (liability) consists of:
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Assets |
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
$ |
278 |
|
|
$ |
281 |
|
|
Risk management |
|
|
|
|
- |
|
|
|
34 |
|
|
Compensation plans |
|
|
|
|
66 |
|
|
|
99 |
|
|
Interest and other deferred deductions |
|
|
|
|
79 |
|
|
|
28 |
|
|
Unrealized foreign exchange losses |
|
|
|
|
6 |
|
|
|
- |
|
|
Non-capital and net capital losses carried forward |
|
|
|
|
1,107 |
|
|
|
1,014 |
|
|
Foreign tax credits |
|
|
|
|
198 |
|
|
|
198 |
|
|
Other |
|
|
|
|
38 |
|
|
|
53 |
|
|
Less: valuation allowance |
|
|
|
|
(195 |
) |
|
|
(187 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Liabilities |
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
(591 |
) |
|
|
(386 |
) |
|
Risk management |
|
|
|
|
(168 |
) |
|
|
(97 |
) |
|
Unrealized foreign exchange gains |
|
|
|
|
- |
|
|
|
(18 |
) |
|
Other |
|
|
|
|
(10 |
) |
|
|
(10 |
) |
|
Net Deferred Income Tax Asset |
|
|
|
$ |
808 |
|
|
$ |
1,009 |
|
As at December 31, 2018, Encana has recorded a valuation allowance against U.S. foreign tax credits, U.S. charitable donations and state losses in the amounts of $156 million (2017 - $156 million), $3 million (2017 - $3 million) and $30 million (2017 - $28 million), respectively, and Canadian unrealized foreign exchange losses in the amount of $6 million (2017 - nil) as it is more likely than not that these benefits will not be realized based on expected future taxable earnings as determined in accordance with the Company’s accounting policies.
99
The net deferred income tax asset (liability) for the following jurisdictions is reflected in the Consolidated Balance Sheet as follows:
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Assets |
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
$ |
548 |
|
|
$ |
555 |
|
|
United States |
|
|
|
|
287 |
|
|
|
488 |
|
|
|
|
|
|
|
835 |
|
|
|
1,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Liabilities |
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
(27 |
) |
|
|
(34 |
) |
|
United States |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
(27 |
) |
|
|
(34 |
) |
|
Net Deferred Income Tax Asset |
|
|
|
$ |
808 |
|
|
$ |
1,009 |
|
Tax pools, loss carryforwards, carryforward interest, charitable donations and tax credits available are as follows:
|
As at December 31 |
|
|
|
2018 |
|
|
Expiration Date |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
|
|
|
|
Tax pools |
|
|
|
$ |
1,699 |
|
|
Indefinite |
|
Net capital losses |
|
|
|
|
13 |
|
|
Indefinite |
|
Non-capital losses |
|
|
|
|
1,121 |
|
|
2027 - 2038 |
|
Charitable donations |
|
|
|
|
3 |
|
|
2022 |
|
United States |
|
|
|
|
|
|
|
|
|
Tax basis |
|
|
|
$ |
3,791 |
|
|
Indefinite |
|
Non-capital losses (Federal) |
|
|
|
|
3,673 |
|
|
2031 - 2038 (1) |
|
Carryforward interest |
|
|
|
|
339 |
|
|
Indefinite |
|
Charitable donations |
|
|
|
|
14 |
|
|
2019 - 2023 |
|
Foreign tax credits |
|
|
|
|
198 |
|
|
2021 - 2025 |
|
(1) |
Includes 2018 non-capital losses of $275 million which have an indefinite expiration date. |
As at December 31, 2018, approximately $10 million (2017 - $3.2 billion) of Encana’s unremitted earnings from its foreign subsidiaries were considered to be permanently reinvested outside of Canada and, accordingly, Encana has not recognized a deferred income tax liability for Canadian income taxes in respect of such earnings. If such earnings were to be remitted to Canada, Encana may be subject to Canadian income taxes and foreign withholding taxes. However, determination of any potential amount of unrecognized deferred income tax liabilities is not practicable. During 2018, approximately $3.4 billion of unremitted earnings of certain foreign subsidiaries were repatriated to Canada, using existing tax attributes, with nominal tax expense.
The following table presents changes in the balance of Encana’s unrecognized tax benefits excluding interest:
|
For the years ended December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
|
|
$ |
(306 |
) |
|
$ |
(286 |
) |
|
Additions for tax positions taken in the current year |
|
|
|
|
(4 |
) |
|
|
- |
|
|
Additions for tax positions of prior years |
|
|
|
|
(2 |
) |
|
|
(1 |
) |
|
Reductions for tax positions of prior years |
|
|
|
|
- |
|
|
|
1 |
|
|
Lapse of statute of limitations |
|
|
|
|
19 |
|
|
|
- |
|
|
Settlements |
|
|
|
|
22 |
|
|
|
- |
|
|
Foreign currency translation |
|
|
|
|
23 |
|
|
|
(20 |
) |
|
Balance, End of Year |
|
|
|
$ |
(248 |
) |
|
$ |
(306 |
) |
100
The unrecognized tax benefit is reflected in the Consolidated Balance Sheet as follows:
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Receivable |
|
|
|
$ |
- |
|
|
$ |
(45 |
) |
|
Other Liabilities and Provisions (See Note 14) |
|
|
|
|
(167 |
) |
|
|
(202 |
) |
|
Deferred Income Tax Asset |
|
|
|
|
(81 |
) |
|
|
(59 |
) |
|
Balance, End of Year |
|
|
|
$ |
(248 |
) |
|
$ |
(306 |
) |
If recognized, all of Encana’s unrecognized tax benefits as at December 31, 2018 would affect Encana’s effective income tax rate. Encana does not anticipate that the amount of unrecognized tax benefits will significantly change during the next 12 months.
Encana recognizes interest accrued in respect of unrecognized tax benefits in interest expense. During 2018, Encana recognized a recovery of $11 million (2017 - expense of $12 million; 2016 - expense of $1 million) in interest expense. As at December 31, 2018, Encana had a liability of $5 million (2017 - $16 million) for interest accrued in respect of unrecognized tax benefits.
Included below is a summary of the tax years, by jurisdiction, that remain statutorily open for examination by the taxing authorities.
|
Jurisdiction |
|
|
|
|
|
Taxation Year |
|
|
|
|
|
|
|
|
|
Canada - Federal |
|
|
|
|
|
2010 - 2018 |
|
Canada - Provincial |
|
|
|
|
|
2010 - 2018 |
|
United States - Federal |
|
|
|
|
|
2015 - 2018 |
|
United States - State |
|
|
|
|
|
2014 - 2018 |
|
Other |
|
|
|
|
|
2017 - 2018 |
Encana and its subsidiaries file income tax returns primarily in Canada and the United States. Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion.
|
7. |
Accounts Receivable and Accrued Revenues |
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade Receivables and Accrued Revenues |
|
|
|
|
|
|
|
|
|
|
|
Oil, NGLs and natural gas |
|
|
|
$ |
319 |
|
|
$ |
425 |
|
|
Midstream and marketing |
|
|
|
|
365 |
|
|
|
284 |
|
|
Derivative financial instruments |
|
|
|
|
36 |
|
|
|
3 |
|
|
Corporate and other |
|
|
|
|
15 |
|
|
|
9 |
|
|
Total Trade Receivables and Accrued Revenues |
|
|
|
|
735 |
|
|
|
721 |
|
|
Prepaids |
|
|
|
|
15 |
|
|
|
21 |
|
|
Deposits and Other |
|
|
|
|
44 |
|
|
|
37 |
|
|
|
|
|
|
|
794 |
|
|
|
779 |
|
|
Allowance for Doubtful Accounts |
|
|
|
|
(5 |
) |
|
|
(5 |
) |
|
|
|
|
|
$ |
789 |
|
|
$ |
774 |
|
Encana’s trade receivables balance primarily consists of oil, NGLs and natural gas sales receivables, marketing revenues and joint interest receivables. Trade receivables are non-interest bearing. In determining the recoverability of trade receivables, the Company considers the age of the outstanding receivable and the credit worthiness of the counterparties. The Company charges uncollectible trade receivables to the allowance for doubtful accounts when it is determined no longer collectible. See Note 23 for further information about credit risk.
101
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
17 |
|
|
$ |
31 |
|
|
$ |
1 |
|
|
USA Operations |
|
|
- |
|
|
|
23 |
|
|
|
209 |
|
|
Total Acquisitions |
|
|
17 |
|
|
|
54 |
|
|
|
210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
(55 |
) |
|
|
(41 |
) |
|
|
(456 |
) |
|
USA Operations |
|
|
(438 |
) |
|
|
(695 |
) |
|
|
(806 |
) |
|
Total Divestitures |
|
|
(493 |
) |
|
|
(736 |
) |
|
|
(1,262 |
) |
|
Net Acquisitions & (Divestitures) |
|
$ |
(476 |
) |
|
$ |
(682 |
) |
|
$ |
(1,052 |
) |
ACQUISITIONS
Acquisitions in 2018 and 2017 in the Canadian and USA Operations primarily included purchases with oil and liquids rich potential. Acquisitions in 2016 in the USA Operations primarily included the purchase of natural gas gathering and water handling assets in Piceance located in Colorado and the purchase of land and property in Eagle Ford with oil and liquids rich potential.
DIVESTITURES
In 2018, amounts received from the sale of assets were $493 million (2017 - $736 million; 2016 - $1,262 million). In 2018, divestitures were $55 million in the Canadian Operations and $438 million in the USA Operations.
Amounts received from the Company’s divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost centre. For divestitures that result in a gain or loss and constitute a business, goodwill is allocated to the divestiture.
Canadian Operations
In 2018, divestitures in the Canadian Operations primarily included the sale of the Pipestone midstream assets located in Alberta.
In 2017, divestitures in the Canadian Operations primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets.
In 2016, divestitures in the Canadian Operations primarily included the sale of the Gordondale assets in Montney located in northwestern Alberta for proceeds of approximately C$600 million ($455 million), after closing adjustments. For the year ended December 31, 2016, Encana recognized a gain of approximately $394 million, before tax, on the sale of the Company’s Gordondale assets in the Canadian cost centre and allocated goodwill of $32 million to the transaction.
USA Operations
In 2018, divestitures in the USA Operations primarily included the sale of the San Juan assets located in northwestern New Mexico.
In 2017, divestitures in the USA Operations primarily included the sale of the Piceance natural gas assets located in northwestern Colorado for proceeds of approximately $605 million, after closing and other adjustments, and the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana. For the year ended December 31, 2017, Encana recognized a gain of approximately $406 million, before tax, on the sale of the Company’s Piceance assets in the U.S. cost centre and allocated goodwill of $216 million to the transaction.
In 2016, divestitures in the USA Operations primarily included the sale of the DJ Basin assets located in northern Colorado for proceeds of approximately $633 million, after closing and other adjustments, as well as the sale of certain
102
natural gas leasehold interests in Piceance located in Colorado for proceeds of approximately $135 million, after closing and other adjustments.
|
9. |
Property, Plant and Equipment, Net |
|
As at December 31 |
|
2018 |
|
|
|
2017 |
|
||||||||||||||||||
|
|
|
Cost |
|
|
Accumulated DD&A |
|
|
Net |
|
|
|
Cost |
|
|
Accumulated DD&A |
|
|
Net |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
13,996 |
|
|
$ |
(13,261 |
) |
|
$ |
735 |
|
|
|
$ |
14,555 |
|
|
$ |
(14,047 |
) |
|
$ |
508 |
|
|
Unproved properties |
|
|
237 |
|
|
|
- |
|
|
|
237 |
|
|
|
|
311 |
|
|
|
- |
|
|
|
311 |
|
|
Other |
|
|
27 |
|
|
|
- |
|
|
|
27 |
|
|
|
|
43 |
|
|
|
- |
|
|
|
43 |
|
|
|
|
|
14,260 |
|
|
|
(13,261 |
) |
|
|
999 |
|
|
|
|
14,909 |
|
|
|
(14,047 |
) |
|
|
862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
27,189 |
|
|
|
(24,099 |
) |
|
|
3,090 |
|
|
|
|
25,610 |
|
|
|
(23,240 |
) |
|
|
2,370 |
|
|
Unproved properties |
|
|
3,493 |
|
|
|
- |
|
|
|
3,493 |
|
|
|
|
4,169 |
|
|
|
- |
|
|
|
4,169 |
|
|
Other |
|
|
8 |
|
|
|
- |
|
|
|
8 |
|
|
|
|
16 |
|
|
|
- |
|
|
|
16 |
|
|
|
|
|
30,690 |
|
|
|
(24,099 |
) |
|
|
6,591 |
|
|
|
|
29,795 |
|
|
|
(23,240 |
) |
|
|
6,555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
7 |
|
|
|
(6 |
) |
|
|
1 |
|
|
|
|
7 |
|
|
|
(5 |
) |
|
|
2 |
|
|
Corporate & Other |
|
|
2,136 |
|
|
|
(755 |
) |
|
|
1,381 |
|
|
|
|
2,299 |
|
|
|
(764 |
) |
|
|
1,535 |
|
|
|
|
$ |
47,093 |
|
|
$ |
(38,121 |
) |
|
$ |
8,972 |
|
|
|
$ |
47,010 |
|
|
$ |
(38,056 |
) |
|
$ |
8,954 |
|
Canadian and USA Operations property, plant and equipment include internal costs directly related to exploration, development and construction activities of $147 million, which have been capitalized during the year ended December 31, 2018 (2017 - $208 million). Included in Corporate and Other are $56 million (2017 - $63 million) of international property costs, which have been fully impaired.
For the years ended December 31, 2018 and December 31, 2017, the Company did not recognize any ceiling test impairments in the Canadian or U.S. cost centres. For the year ended December 31, 2016, the Company recognized before-tax ceiling test impairments of $493 million in the Canadian cost centre and $903 million in the U.S. cost centre. The impairments recognized in 2016 resulted primarily from the decline in the 12-month average trailing prices which reduced proved reserves volumes and values.
The 12-month average trailing prices used in the ceiling test calculations reflect benchmark prices adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality. The benchmark prices are disclosed in Note 27.
Capital Lease Arrangements
The Company has several lease arrangements that are accounted for as capital leases including an office building and an offshore production platform.
As at December 31, 2018, the total carrying value of assets under capital lease was $41 million (2017 - $46 million), net of accumulated amortization of $650 million (2017 - $684 million). Liabilities for the capital lease arrangements are included in other liabilities and provisions in the Consolidated Balance Sheet and are disclosed in Note 14.
Other Arrangement
As at December 31, 2018, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,133 million (2017 - $1,255 million) related to The Bow office building, which is under a 25-year lease agreement. The Bow asset is being depreciated over the 60-year estimated life of the building. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized as disclosed in Note 14.
Refer to Note 1 for further information regarding the change in accounting for The Bow office building upon adoption of ASU 2016-02, “Leases” under Topic 842 on January 1, 2019.
103
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Investments |
|
|
|
$ |
22 |
|
|
$ |
26 |
|
|
Long-Term Receivables |
|
|
|
|
79 |
|
|
|
72 |
|
|
Deferred Charges |
|
|
|
|
9 |
|
|
|
7 |
|
|
Other |
|
|
|
|
37 |
|
|
|
39 |
|
|
|
|
|
|
$ |
147 |
|
|
$ |
144 |
|
|
11. |
Goodwill |
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
|
|
$ |
696 |
|
|
$ |
650 |
|
|
Foreign Currency Translation Adjustment |
|
|
|
|
(56 |
) |
|
|
46 |
|
|
Balance, End of Year |
|
|
|
|
640 |
|
|
|
696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
|
|
|
1,913 |
|
|
|
2,129 |
|
|
Divested During the Year (See Note 8) |
|
|
|
|
- |
|
|
|
(216 |
) |
|
Balance, End of Year |
|
|
|
|
1,913 |
|
|
|
1,913 |
|
|
Total Goodwill |
|
|
|
$ |
2,553 |
|
|
$ |
2,609 |
|
During 2018, the Company had no additions or dispositions relating to goodwill. The change in the Canada goodwill balance reflects movements due to foreign currency translation. During 2017, the Company derecognized goodwill of $216 million upon the divestiture of the Piceance assets as described in Note 8.
Goodwill was assessed for impairment as at December 31, 2018 and December 31, 2017. The fair values of the Canada and United States reporting units were determined to be greater than the respective carrying values of the reporting units. Accordingly, no goodwill impairments were recognized. The Company has not recognized any historical cumulative goodwill impairments.
12. Accounts Payable and Accrued Liabilities
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade Payables |
|
|
|
$ |
233 |
|
|
$ |
258 |
|
|
Capital Accruals |
|
|
|
|
277 |
|
|
|
319 |
|
|
Royalty and Production Accruals |
|
|
|
|
311 |
|
|
|
278 |
|
|
Other Accruals |
|
|
|
|
295 |
|
|
|
216 |
|
|
Interest Payable |
|
|
|
|
69 |
|
|
|
69 |
|
|
Current Portion of Long-Term Incentive Costs (See Note 20) |
|
|
|
|
131 |
|
|
|
152 |
|
|
Current Portion of Capital Lease Obligations (See Note 14) |
|
|
|
|
84 |
|
|
|
79 |
|
|
Current Portion of Asset Retirement Obligation (See Note 15) |
|
|
|
|
90 |
|
|
|
44 |
|
|
|
|
|
|
$ |
1,490 |
|
|
$ |
1,415 |
|
Payables and accruals are non-interest bearing. Interest payable represents amounts accrued related to Encana’s unsecured notes as disclosed in Note 13.
104
|
As at December 31 |
|
Note |
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Dollar Denominated Debt |
|
|
|
|
|
|
|
|
|
|
|
Revolving credit and term loan borrowings |
|
A |
|
$ |
- |
|
|
$ |
- |
|
|
U.S. Unsecured Notes: |
|
B |
|
|
|
|
|
|
|
|
|
6.50% due May 15, 2019 |
|
|
|
|
500 |
|
|
|
500 |
|
|
3.90% due November 15, 2021 |
|
|
|
|
600 |
|
|
|
600 |
|
|
8.125% due September 15, 2030 |
|
|
|
|
300 |
|
|
|
300 |
|
|
7.20% due November 1, 2031 |
|
|
|
|
350 |
|
|
|
350 |
|
|
7.375% due November 1, 2031 |
|
|
|
|
500 |
|
|
|
500 |
|
|
6.50% due August 15, 2034 |
|
|
|
|
750 |
|
|
|
750 |
|
|
6.625% due August 15, 2037 |
|
|
|
|
462 |
|
|
|
462 |
|
|
6.50% due February 1, 2038 |
|
|
|
|
505 |
|
|
|
505 |
|
|
5.15% due November 15, 2041 |
|
|
|
|
244 |
|
|
|
244 |
|
|
Total Principal |
|
F |
|
|
4,211 |
|
|
|
4,211 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Value of Debt Acquired |
|
C |
|
|
22 |
|
|
|
26 |
|
|
Unamortized Debt Discounts and Issuance Costs |
|
D |
|
|
(35 |
) |
|
|
(40 |
) |
|
Total Long-Term Debt |
|
|
|
$ |
4,198 |
|
|
$ |
4,197 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Portion |
|
E |
|
$ |
500 |
|
|
$ |
- |
|
|
Long-Term Portion |
|
|
|
|
3,698 |
|
|
|
4,197 |
|
|
|
|
|
|
$ |
4,198 |
|
|
$ |
4,197 |
|
|
A) |
REVOLVING CREDIT AND TERM LOAN BORROWINGS |
At December 31, 2018, Encana had in place committed revolving U.S. dollar denominated bank credit facilities totaling $4.0 billion which included $2.5 billion on a revolving bank credit facility for Encana and $1.5 billion on a revolving bank credit facility for a U.S. subsidiary. The facilities are extendible from time to time, but not more than once per year, for a period not longer than five years plus 90 days from the date of the extension request, at the option of the lenders and upon notice from Encana. The facilities mature in July 2022, and are fully revolving up to maturity.
Encana is subject to a financial covenant in its credit facility agreements whereby financing debt to adjusted capitalization cannot exceed 60 percent. Financing debt primarily includes total long-term debt and capital lease obligations. Adjusted capitalization is calculated as the sum of total financing debt, shareholders’ equity and a $7.7 billion equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. As at December 31, 2018, the Company is in compliance with all financial covenants.
The Encana facility, which remained unused at December 31, 2018, is unsecured and bears interest at the lenders’ rates for Canadian prime, U.S. base rate, Bankers’ Acceptances or LIBOR, plus applicable margins. The U.S. subsidiary facility, which remained unused as at December 31, 2018, bears interest at either the lenders’ U.S. base rate or LIBOR, plus applicable margins.
Standby fees paid in 2018 relating to revolving credit and term loan agreements were approximately $15 million (2017 - $15 million; 2016 - $14 million).
|
B) |
UNSECURED NOTES |
Shelf Prospectuses
Encana renewed its shelf prospectus in Canada in 2018 and filed a shelf registration statement in the U.S. in 2017, whereby the Company may issue from time to time debt securities, common shares, Class A preferred shares, subscription receipts, warrants, units, share purchase contracts and share purchase units in Canada and/or the U.S. At December 31, 2018, $6.0 billion remained accessible under the Canadian shelf prospectus. The availability of issuing securities under the Canadian shelf prospectus and U.S. shelf registration statement is dependent upon market conditions.
105
Unsecured notes include medium-term notes and senior notes that are issued from time to time under trust indentures and have equal priority with respect to the payment of both principal and interest.
|
C) |
INCREASE IN VALUE OF DEBT ACQUIRED |
Certain of the notes and debentures of the Company were acquired in business combinations and were accounted for at their fair value at the dates of acquisition. The difference between the fair value and the principal amount of the debt is being amortized over the remaining life of the outstanding debt acquired, which is approximately 12 years.
|
D) |
UNAMORTIZED DEBT DISCOUNTS AND ISSUANCE COSTS |
Long-term debt premiums and discounts are capitalized within long-term debt and are being amortized using the effective interest method. During 2018 and 2017, no debt premiums or discounts were capitalized. Issuance costs are amortized over the term of the related debt.
|
E) |
CURRENT PORTION OF LONG-TERM DEBT |
As at December 31, 2018, the current portion of long-term debt was $500 million (2017 - nil).
|
F) |
MANDATORY DEBT PAYMENTS |
|
|
|
|
|
Principal |
|
|
Interest |
|
||
|
As at December 31 |
|
|
|
Amount |
|
|
Amount |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
|
|
$ |
500 |
|
|
$ |
251 |
|
|
2020 |
|
|
|
- |
|
|
|
234 |
|
|
|
2021 |
|
|
|
|
600 |
|
|
|
235 |
|
|
2022 |
|
|
|
- |
|
|
|
211 |
|
|
|
2023 |
|
|
|
- |
|
|
|
211 |
|
|
|
Thereafter |
|
|
|
|
3,111 |
|
|
|
2,335 |
|
|
Total |
|
|
|
$ |
4,211 |
|
|
$ |
3,477 |
|
As at December 31, 2018, total long-term debt had a carrying value of $4,198 million and a fair value of $4,511 million (2017 - carrying value of $4,197 million and a fair value of $5,042 million). The estimated fair value of long-term borrowings is categorized within Level 2 of the fair value hierarchy and has been determined based on market information of long-term debt with similar terms and maturity, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.
|
14. |
Other Liabilities and Provisions |
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
The Bow Office Building |
|
|
|
$ |
1,224 |
|
|
$ |
1,344 |
|
|
Capital Lease Obligations |
|
|
|
|
211 |
|
|
|
295 |
|
|
Unrecognized Tax Benefits (See Note 6) |
|
|
|
|
167 |
|
|
|
202 |
|
|
Pensions and Other Post-Employment Benefits |
|
|
|
|
105 |
|
|
|
116 |
|
|
Long-Term Incentive Costs (See Note 20) |
|
|
|
|
34 |
|
|
|
175 |
|
|
Other Derivative Contracts (See Notes 22, 23) |
|
|
|
|
10 |
|
|
|
14 |
|
|
Other |
|
|
|
|
18 |
|
|
|
21 |
|
|
|
|
|
|
$ |
1,769 |
|
|
$ |
2,167 |
|
106
As described in Note 9, Encana has recognized the accumulated costs for The Bow office building, which is under a 25-year lease agreement. At the conclusion of the lease term, the remaining asset and corresponding liability are expected to be derecognized. Encana has also subleased approximately 50 percent of The Bow office space under the lease agreement. The total expected future principal and interest payments related to the 25-year lease agreement and the total undiscounted future amounts expected to be recovered from the sublease are outlined below.
|
|
|
2019 |
|
|
2020 |
|
|
2021 |
|
|
2022 |
|
|
2023 |
|
|
Thereafter |
|
|
Total |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Lease Payments |
|
$ |
70 |
|
|
$ |
71 |
|
|
$ |
72 |
|
|
$ |
72 |
|
|
$ |
73 |
|
|
$ |
1,118 |
|
|
$ |
1,476 |
|
|
Less: Amounts Representing Interest |
|
|
59 |
|
|
|
58 |
|
|
|
58 |
|
|
|
57 |
|
|
|
56 |
|
|
|
681 |
|
|
|
969 |
|
|
Present Value of Expected Future |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Payments |
|
$ |
11 |
|
|
$ |
13 |
|
|
$ |
14 |
|
|
$ |
15 |
|
|
$ |
17 |
|
|
$ |
437 |
|
|
$ |
507 |
|
|
Sublease Recoveries (undiscounted) |
|
$ |
(35 |
) |
|
$ |
(35 |
) |
|
$ |
(35 |
) |
|
$ |
(35 |
) |
|
$ |
(36 |
) |
|
$ |
(550 |
) |
|
$ |
(726 |
) |
Refer to Note 1 for further information regarding the change in accounting for The Bow office building upon adoption of ASU 2016-02, “Leases” under Topic 842 on January 1, 2019.
Capital Lease Obligations
As described in Note 9, the Company has several lease arrangements that are accounted for as capital leases including an office building and the Deep Panuke offshore Production Field Centre (“PFC”). Variable interests related to the PFC are described in Note 18.
The total expected future lease payments related to the Company’s capital lease obligations are outlined below.
|
|
|
2019 |
|
|
2020 |
|
|
2021 |
|
|
2022 |
|
|
2023 |
|
|
Thereafter |
|
|
Total |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Lease Payments |
|
$ |
99 |
|
|
$ |
99 |
|
|
$ |
87 |
|
|
$ |
8 |
|
|
$ |
8 |
|
|
$ |
30 |
|
|
$ |
331 |
|
|
Less: Amounts Representing Interest |
|
|
15 |
|
|
|
10 |
|
|
|
4 |
|
|
|
2 |
|
|
|
2 |
|
|
|
3 |
|
|
|
36 |
|
|
Present Value of Expected Future |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Payments |
|
$ |
84 |
|
|
$ |
89 |
|
|
$ |
83 |
|
|
$ |
6 |
|
|
$ |
6 |
|
|
$ |
27 |
|
|
$ |
295 |
|
|
15. |
Asset Retirement Obligation |
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation, Beginning of Year |
|
|
|
$ |
514 |
|
|
$ |
687 |
|
|
Liabilities Incurred and Acquired |
|
|
|
|
17 |
|
|
|
11 |
|
|
Liabilities Settled and Divested |
|
|
|
|
(56 |
) |
|
|
(333 |
) |
|
Change in Estimated Future Cash Outflows |
|
|
|
|
(20 |
) |
|
|
88 |
|
|
Accretion Expense |
|
|
|
|
32 |
|
|
|
37 |
|
|
Foreign Currency Translation |
|
|
|
|
(32 |
) |
|
|
24 |
|
|
Asset Retirement Obligation, End of Year |
|
|
|
$ |
455 |
|
|
$ |
514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Portion (See Note 12) |
|
|
|
$ |
90 |
|
|
$ |
44 |
|
|
Long-Term Portion |
|
|
|
|
365 |
|
|
|
470 |
|
|
|
|
|
|
$ |
455 |
|
|
$ |
514 |
|
107
AUTHORIZED
The Company is authorized to issue an unlimited number of no par value common shares and Class A Preferred Shares limited to a number equal to not more than 20 percent of the issued and outstanding number of common shares at the time of issuance. No Class A Preferred Shares are outstanding.
ISSUED AND OUTSTANDING
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||||||||||||||
|
|
|
Number (millions) |
|
|
Amount |
|
|
Number (millions) |
|
|
Amount |
|
|
Number (millions) |
|
|
Amount |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Shares Outstanding, Beginning of Year |
|
|
973.1 |
|
|
$ |
4,757 |
|
|
|
973.0 |
|
|
$ |
4,756 |
|
|
|
849.8 |
|
|
$ |
3,621 |
|
|
Common Shares Purchased |
|
|
(20.7 |
) |
|
|
(102 |
) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
||||
|
Common Shares Issued |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
123.1 |
|
|
|
1,134 |
|
||||
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
|
0.1 |
|
|
|
1 |
|
|
|
0.1 |
|
|
|
1 |
|
|
|
0.1 |
|
|
|
1 |
|
|
Common Shares Outstanding, End of Year |
|
|
952.5 |
|
|
$ |
4,656 |
|
|
|
973.1 |
|
|
$ |
4,757 |
|
|
|
973.0 |
|
|
$ |
4,756 |
|
NORMAL COURSE ISSUER BID
On February 26, 2018, the Company announced it received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019.
All purchases are made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, with any excess allocated to retained earnings/accumulated deficit.
During the year ended December 31, 2018, the Company purchased approximately 20.7 million common shares for total consideration of approximately $250 million. Of the amount paid, $102 million was charged to share capital and $148 million was charged to retained earnings.
On February 13, 2019, the Company confirmed it will proceed with its previously announced plans to spend up to $1.25 billion to purchase common shares, for cancellation, subject to the receipt of regulatory approvals. On February 27, 2019, the Company announced that the TSX accepted its notice of intention to commence a NCIB beginning March 4, 2019 and ending March 3, 2020.
SHARE OFFERING
On September 19, 2016, Encana filed prospectus supplements (the “2016 Share Offering”) to the Company’s shelf prospectuses for the issuance of 107,000,000 common shares and granted an over-allotment option for up to an additional 16,050,000 common shares at a price of $9.35 per common share, pursuant to an underwriting agreement. The aggregate gross proceeds from the 2016 Share Offering, including the exercise in full of the over-allotment option, were approximately $1.15 billion. After deducting underwriters’ fees and costs of the 2016 Share Offering, the net cash proceeds received were approximately $1.13 billion.
DIVIDEND REINVESTMENT PLAN
During the year ended December 31, 2018, Encana issued 69,329 common shares totaling $0.6 million under the Company’s dividend reinvestment plan (“DRIP”) (2017 - issued 58,480 common shares totaling $0.6 million; 2016 - issued 121,249 common shares totaling $0.9 million).
DIVIDENDS
During the year ended December 31, 2018, Encana declared and paid dividends of $0.06 per common share totaling $57 million (2017 - $0.06 per common share totaling $58 million; 2016 - $0.06 per common share totaling $52 million). The Company’s quarterly dividend payment in 2018, 2017 and 2016 was $0.015 per common share.
108
Common shares issued as part of the 2016 Share Offering described above were not eligible to receive the dividends paid on September 30, 2016 .
For the year ended December 31, 2018, the dividends paid included $0.6 million in common shares, as disclosed above, which were issued in lieu of cash dividends under the DRIP (2017 - $0.6 million; 2016 - $0.9 million).
On February 27, 2019, the Board of Directors declared a dividend of $0.01875 per common share payable on March 29, 2019 to common shareholders of record as of March 15, 2019.
EARNINGS PER COMMON SHARE
The following table presents the computation of net earnings (loss) per common share:
|
For the years ended December 31 (US$ millions, except per share amounts) |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
$ |
1,069 |
|
|
$ |
827 |
|
|
$ |
(944 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Common Shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding - Basic |
|
|
959.8 |
|
|
|
973.1 |
|
|
|
882.6 |
|
|
Effect of dilutive securities |
|
- |
|
|
- |
|
|
- |
|
|||
|
Weighted Average Common Shares Outstanding - Diluted |
|
|
959.8 |
|
|
|
973.1 |
|
|
|
882.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
|
$ |
1.11 |
|
|
$ |
0.85 |
|
|
$ |
(1.07 |
) |
ENCANA STOCK OPTION PLAN
Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the market value of the common shares on the date the options are granted. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. Options granted before February 2015 expire five years after the date granted.
All options outstanding as at December 31, 2018 have associated Tandem Stock Appreciation Rights (“TSARs”) attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of the exercise over the original grant price. In addition, certain stock options granted are performance-based. The Performance TSARs vest and expire under the same terms and conditions as the underlying option. Vesting is also subject to Encana attaining prescribed performance relative to predetermined key measures. Historically, most holders of options with TSARs have elected to exercise their stock options as a Stock Appreciation Right (“SAR”) in exchange for a cash payment. As a result, outstanding TSARs are not considered potentially dilutive securities. See Note 20 for further information on Encana’s outstanding and exercisable TSARs and Performance TSARs.
At December 31, 2018, there were 38.2 million common shares reserved for issuance under stock option plans (2017 - 33.3 million; 2016 - 32.2 million).
ENCANA RESTRICTED SHARE UNITS (“RSUs”)
Encana has a share-based compensation plan whereby eligible employees and Directors are granted RSUs. An RSU is a conditional grant to receive the equivalent of an Encana common share upon vesting of the RSUs and in accordance with the terms and conditions of the RSU Plans and grant agreements. The Company currently settles vested RSUs in cash. As a result, RSUs are not considered potentially dilutive securities. See Note 20 for further information on Encana’s outstanding RSUs.
109
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
$ |
1,029 |
|
|
$ |
1,200 |
|
|
$ |
1,383 |
|
|
Change in Foreign Currency Translation Adjustment |
|
|
(53 |
) |
|
|
(171 |
) |
|
|
(183 |
) |
|
Balance, End of Year |
|
$ |
976 |
|
|
$ |
1,029 |
|
|
$ |
1,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and Other Post-Employment Benefit Plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
$ |
13 |
|
|
$ |
10 |
|
|
$ |
7 |
|
|
Net Actuarial Gains and (Losses) (See Note 21) |
|
|
14 |
|
|
|
7 |
|
|
|
6 |
|
|
Income Taxes |
|
|
(3 |
) |
|
|
(2 |
) |
|
|
(2 |
) |
|
Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 21) |
|
|
(1 |
) |
|
|
- |
|
|
|
(1 |
) |
|
Income Taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Reclassification of Net Prior Service Costs to Net Earnings (See Note 21) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
- |
|
|
Income Taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Curtailment in Net Defined Periodic Benefit Cost (See Note 21) |
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
|
Income Taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Balance, End of Year |
|
$ |
22 |
|
|
$ |
13 |
|
|
$ |
10 |
|
|
Total Accumulated Other Comprehensive Income |
|
$ |
998 |
|
|
$ |
1,042 |
|
|
$ |
1,210 |
|
|
18. |
Variable Interest Entities |
Production Field Centre
In 2008, Encana entered into a contract for the design, construction and operation of the PFC at its Deep Panuke facility. Upon commencement of operations in December 2013, Encana recognized the PFC as a capital lease asset. Under the lease contract, Encana has a purchase option and the option to extend the lease for 12 one-year terms at fixed prices after the initial lease term expires in 2021.
As a result of the purchase option and fixed price renewal options, Encana determined it holds variable interests and that the related leasing entity qualifies as a variable interest entity (“VIE”). Encana is not the primary beneficiary of the VIE as the Company does not have the power to direct the activities that most significantly impact the VIE’s economic performance. Encana is not required to provide any financial support or guarantees to the leasing entity or its affiliates, other than the contractual payments under the lease and operating agreements. Encana’s maximum exposure is the expected lease payments over the initial contract term. As at December 31, 2018, Encana had a capital lease obligation of $240 million (2017 - $314 million) related to the PFC.
Veresen Midstream Limited Partnership
Veresen Midstream Limited Partnership (“VMLP”) provides gathering, compression and processing services under various agreements related to the Company’s development of liquids and natural gas production in the Montney play. As at December 31, 2018, VMLP provides approximately 1,150 MMcf/d of natural gas gathering and compression and 887 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from up to 13 to 27 years and have various renewal terms providing up to a potential maximum of 10 years.
Encana has determined that VMLP is a VIE and that Encana holds variable interests in VMLP. Encana is not the primary beneficiary as the Company does not have the power to direct the activities that most significantly impact VMLP’s economic performance. These key activities relate to the construction, operation, maintenance and marketing of the assets owned by VMLP. The variable interests arise from certain terms under the various long-term service agreements and include: i) a take or pay for volumes in certain agreements; ii) an operating fee of which a portion can be converted into a fixed fee once VMLP assumes operatorship of certain assets; and iii) a potential payout of minimum costs in certain agreements. The potential payout of minimum costs will be assessed in the eighth year of the assets’ service period and is based on whether there is an overall shortfall of total system cash flows from natural gas gathered and compressed under certain agreements. The potential payout amount can be reduced in the event VMLP markets unutilized capacity to third party users. Encana is not required to provide any financial support or guarantees to VMLP.
110
As a result of Encana’s involvement with VMLP, the maximum total exposure, which represents the potential exposure to Encana in the event the assets under the agreements are deemed worthless, is estimated to be $2,295 million as at December 31, 2018. The estimate comprises the take or pay volume commitments and the potential payout of minimum costs. The take or pay volume commitments associated with certain gathering and processing assets are included in Note 25 under Transportation and Processing. The potential payout requirement is highly uncertain as the amount is contingent on future production estimates, pace of development and the amount of capacity contracted to third parties. As at December 31, 2018, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment.
|
19. |
Restructuring Charges |
In February 2016, Encana announced workforce reductions to better align staffing levels and the organizational structure with the Company’s reduced capital spending program as a result of the low commodity price environment. During 2016, the Company incurred total restructuring charges of $34 million, before tax, primarily related to severance costs, of which $7 million remained accrued as at December 31, 2016. As at December 31, 2017, all restructuring costs were paid.
Restructuring charges are included in administrative expense presented in the Corporate and Other segment in the Consolidated Statement of Earnings.
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee Severance and Benefits |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
33 |
|
|
Outplacement, Moving and Other Expenses |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
34 |
|
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Restructuring Accrual, Beginning of Year |
|
$ |
- |
|
|
$ |
7 |
|
|
$ |
13 |
|
|
Current Year Restructuring Expenses Incurred |
|
|
- |
|
|
|
- |
|
|
|
34 |
|
|
Restructuring Costs Paid |
|
|
- |
|
|
|
(7 |
) |
|
|
(40 |
) |
|
Outstanding Restructuring Accrual, End of Year (1) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
7 |
|
|
(1) |
Included in accounts payable and accrued liabilities in the Consolidated Balance Sheet. |
|
20. |
Compensation Plans |
Encana has a number of compensation arrangements under which the Company awards various types of long-term incentive grants to eligible employees and Directors. They may include TSARs, Performance TSARs, SARs, Performance Share Units (“PSUs”), Deferred Share Units (“DSUs”) and RSUs. These compensation arrangements are share-based.
Encana accounts for TSARs, Performance TSARs, SARs, PSUs, and RSUs as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.
111
The following weighted average assumptions were used to determine the fair value of the share units outstanding:
|
|
|
US$ Share Units |
||||
|
As at December 31 |
|
2018 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
Risk Free Interest Rate |
|
1.85% |
|
1.67% |
|
0.75% |
|
Dividend Yield |
|
1.04% |
|
0.45% |
|
0.51% |
|
Expected Volatility Rate (1) |
|
51.28% |
|
57.87% |
|
57.18% |
|
Expected Term |
|
1.4 yrs |
|
1.4 yrs |
|
1.9 yrs |
|
Market Share Price |
|
US$5.78 |
|
US$13.33 |
|
US$11.74 |
|
|
|
C$ Share Units |
||||
|
As at December 31 |
|
2018 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
Risk Free Interest Rate |
|
1.85% |
|
1.67% |
|
0.75% |
|
Dividend Yield |
|
0.99% |
|
0.46% |
|
0.50% |
|
Expected Volatility Rate (1) |
|
48.68% |
|
54.10% |
|
53.24% |
|
Expected Term |
|
1.8 yrs |
|
1.5 yrs |
|
1.9 yrs |
|
Market Share Price |
|
C$7.88 |
|
C$16.77 |
|
C$15.76 |
|
(1) |
Volatility was estimated using historical rates. |
The Company has recognized the following share-based compensation costs:
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Compensation Costs of Transactions Classified as Cash-Settled |
|
$ |
(65 |
) |
|
$ |
165 |
|
|
$ |
174 |
|
|
Less: Total Share-Based Compensation Costs Capitalized |
|
19 |
|
|
|
(55 |
) |
|
|
(40 |
) |
|
|
Total Share-Based Compensation Expense (Recovery) |
|
$ |
(46 |
) |
|
$ |
110 |
|
|
$ |
134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized on the Consolidated Statement of Earnings in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
$ |
(13 |
) |
|
$ |
34 |
|
|
$ |
48 |
|
|
Administrative |
|
|
(33 |
) |
|
|
76 |
|
|
|
86 |
|
|
|
|
$ |
(46 |
) |
|
$ |
110 |
|
|
$ |
134 |
|
As at December 31, 2018, the liability for share-based payment transactions totaled $165 million (2017 - $327 million), of which $131 million (2017 - $152 million) is recognized in accounts payable and accrued liabilities and $34 million (2017 - $175 million) is recognized in other liabilities and provisions in the Consolidated Balance Sheet.
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability for Cash-Settled Share-Based Payment Transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested |
|
$ |
148 |
|
|
$ |
274 |
|
|
$ |
171 |
|
|
Vested |
|
|
17 |
|
|
|
53 |
|
|
|
37 |
|
|
|
|
$ |
165 |
|
|
$ |
327 |
|
|
$ |
208 |
|
The following sections outline certain information related to Encana’s compensation plans as at December 31, 2018.
|
A) |
TANDEM STOCK APPRECIATION RIGHTS |
All options to purchase common shares issued to eligible Canadian-based employees under the Encana Stock Option Plan have associated TSARs attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of exercise over the original grant price. TSARs granted vest and are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. TSARs granted before February 2015 expire five years after the date granted.
112
The following tables summarize information related to the TSARs:
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||||||||||
|
(thousands of units) |
|
|
|
Outstanding TSARs |
|
|
Weighted Average Exercise Price (C$) |
|
|
Outstanding TSARs |
|
|
Weighted Average Exercise Price (C$) |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
|
15,270 |
|
|
|
14.87 |
|
|
|
15,482 |
|
|
|
14.92 |
|
|
Granted |
|
|
|
|
872 |
|
|
|
13.76 |
|
|
|
850 |
|
|
|
15.43 |
|
|
Exercised - SARs |
|
|
|
|
(371 |
) |
|
|
7.44 |
|
|
|
(316 |
) |
|
|
5.56 |
|
|
Exercised - Options |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
Forfeited |
|
|
|
|
(307 |
) |
|
|
15.60 |
|
|
|
(218 |
) |
|
|
19.55 |
|
|
Expired |
|
|
|
|
(5,097 |
) |
|
|
18.06 |
|
|
|
(528 |
) |
|
|
20.99 |
|
|
Outstanding, End of Year |
|
|
|
|
10,367 |
|
|
|
13.45 |
|
|
|
15,270 |
|
|
|
14.87 |
|
|
Exercisable, End of Year |
|
|
|
|
7,293 |
|
|
|
15.02 |
|
|
|
10,736 |
|
|
|
17.42 |
|
|
As at December 31, 2018 |
|
Outstanding TSARs |
|
|
Exercisable TSARs |
|
||||||||||||||
|
Range of Exercise Price (C$) |
|
Number of TSARs (thousands of units) |
|
|
Weighted Average Remaining Contractual Life (years) |
|
|
Weighted Average Exercise Price (C$) |
|
|
Number of TSARs (thousands of units) |
|
|
Weighted Average Exercise Price (C$) |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.00 to 9.99 |
|
|
3,565 |
|
|
|
4.17 |
|
|
|
5.56 |
|
|
|
1,926 |
|
|
|
5.56 |
|
|
10.00 to 19.99 |
|
|
3,380 |
|
|
|
4.33 |
|
|
|
14.55 |
|
|
|
1,946 |
|
|
|
14.63 |
|
|
20.00 to 29.99 |
|
|
3,422 |
|
|
|
0.16 |
|
|
|
20.58 |
|
|
|
3,421 |
|
|
|
20.58 |
|
|
|
|
|
10,367 |
|
|
|
2.90 |
|
|
|
13.45 |
|
|
|
7,293 |
|
|
|
15.02 |
|
During the year, Encana recorded a reduction of compensation costs of $35 million related to the TSARs (2017 - compensation costs of $12 million; 2016 - compensation costs of $39 million).
As at December 31, 2018, there was approximately $0.2 million of unrecognized compensation costs (2017 - $8 million) related to unvested TSARs. The costs are expected to be recognized over a weighted average period of 0.9 years.
|
B) |
PERFORMANCE TANDEM STOCK APPRECIATION RIGHTS |
In 2017, all Performance TSARs expired and there were no remaining obligations. Accordingly, Encana did not record any compensation costs related to the Performance TSARs in 2018 (2017 - reduction of compensation costs of $2 million; 2016 - compensation costs of $2 million).
|
C) |
STOCK APPRECIATION RIGHTS |
U.S. dollar denominated SARs are granted to eligible U.S.-based employees, which entitle the employee to receive a payment equal to the excess of the market price of Encana’s common shares at the time of exercise over the original grant price of the right. SARs granted vest and are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. SARs granted before February 2015 expire five years after the date granted. The Company currently settles vested SARs in cash.
113
The following tables summarize information related to the U.S. dollar denominated SARs:
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||||||||||
|
(thousands of units) |
|
|
|
Outstanding SARs |
|
|
Weighted Average Exercise Price (US$) |
|
|
Outstanding SARs |
|
|
Weighted Average Exercise Price (US$) |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
|
6,343 |
|
|
|
14.25 |
|
|
|
6,721 |
|
|
|
14.55 |
|
|
Granted |
|
|
|
|
377 |
|
|
|
11.02 |
|
|
|
349 |
|
|
|
11.75 |
|
|
Exercised |
|
|
|
|
(442 |
) |
|
|
5.89 |
|
|
|
(147 |
) |
|
|
4.69 |
|
|
Forfeited |
|
|
|
|
(302 |
) |
|
|
10.88 |
|
|
|
(418 |
) |
|
|
17.94 |
|
|
Expired |
|
|
|
|
(1,875 |
) |
|
|
17.94 |
|
|
|
(162 |
) |
|
|
20.57 |
|
|
Outstanding, End of Year |
|
|
|
|
4,101 |
|
|
|
13.42 |
|
|
|
6,343 |
|
|
|
14.25 |
|
|
Exercisable, End of Year |
|
|
|
|
3,105 |
|
|
|
15.19 |
|
|
|
4,611 |
|
|
|
16.85 |
|
|
As at December 31, 2018 |
|
Outstanding SARs |
|
|
Exercisable SARs |
|
||||||||||||||
|
Range of Exercise Price (US$) |
|
Number of SARs (thousands of units) |
|
|
Weighted Average Remaining Contractual Life (years) |
|
|
Weighted Average Exercise Price (US$) |
|
|
Number of SARs (thousands of units) |
|
|
Weighted Average Exercise Price (US$) |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.00 to 9.99 |
|
|
875 |
|
|
|
4.17 |
|
|
|
4.06 |
|
|
|
401 |
|
|
|
4.06 |
|
|
10.00 to 19.99 |
|
|
2,909 |
|
|
|
1.97 |
|
|
|
15.24 |
|
|
|
2,387 |
|
|
|
16.10 |
|
|
20.00 to 29.99 |
|
|
317 |
|
|
|
0.58 |
|
|
|
22.47 |
|
|
|
317 |
|
|
|
22.47 |
|
|
|
|
|
4,101 |
|
|
|
2.33 |
|
|
|
13.42 |
|
|
|
3,105 |
|
|
|
15.19 |
|
During the year, Encana recorded a reduction of compensation costs of $12 million related to the SARs (2017 - compensation costs of $6 million; 2016 - compensation costs of $13 million).
As at December 31, 2018, there was approximately $0.3 million of unrecognized compensation costs (2017 - $4 million) related to unvested U.S. dollar denominated SARs. The costs are expected to be recognized over a weighted average period of 1.0 years.
|
D) |
PERFORMANCE SHARE UNITS |
PSUs are granted to eligible employees, which entitle the employee to receive, upon vesting, a payment equal to the value of one Encana common share for each PSU held, subject to the terms and conditions of the PSU Plan. PSUs vest three years from the date granted, provided the employee remains actively employed with Encana on the vesting date. The Company currently settles vested PSUs in cash. Based on the performance assessment, up to a maximum of two times the original PSU grant may be eligible to vest in respect of the year being measured. The respective proportion of the original PSU grant deemed eligible to vest for each year will be valued and the notional cash value deposited to a PSU account, with payout deferred to the final vesting date.
The ultimate value of the PSUs will depend upon Encana’s performance relative to predetermined corresponding performance targets measured over a three-year period. For grants commencing in 2013, performance is measured over a three-year period relative to a specified peer group.
The following table summarizes information related to the PSUs:
|
(thousands of units) |
|
Canadian Dollar Denominated Outstanding PSUs |
|
|
U.S. Dollar Denominated Outstanding PSUs |
|
||||||||||
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested and Outstanding, Beginning of Year |
|
|
6,002 |
|
|
|
5,218 |
|
|
|
3,375 |
|
|
|
2,907 |
|
|
Granted |
|
|
1,601 |
|
|
|
1,234 |
|
|
|
910 |
|
|
|
704 |
|
|
Vested and Released |
|
|
(1,618 |
) |
|
|
(433 |
) |
|
|
(789 |
) |
|
|
(123 |
) |
|
Units, in Lieu of Dividends |
|
|
37 |
|
|
|
33 |
|
|
|
21 |
|
|
|
18 |
|
|
Forfeited |
|
|
(72 |
) |
|
|
(50 |
) |
|
|
(256 |
) |
|
|
(131 |
) |
|
Unvested and Outstanding, End of Year |
|
|
5,950 |
|
|
|
6,002 |
|
|
|
3,261 |
|
|
|
3,375 |
|
114
During the year, Encana recorded compensation costs of $10 million related to the outstanding PSUs (2017 - compensation costs of $48 million; 2016 - compensation costs of $29 million).
As at December 31, 2018, there was approximately $16 million of unrecognized compensation costs (2017 - $53 million) related to unvested PSUs. The costs are expected to be recognized over a weighted average period of 0.8 years.
|
E) |
DEFERRED SHARE UNITS |
The Company has in place a program whereby Directors and certain key employees are issued DSUs, which vest immediately, are equivalent in value to an Encana common share and are settled in cash.
Under the DSU Plan, employees have the option to convert either 25 or 50 percent of their annual High Performance Results (“HPR”) award into DSUs. The number of DSUs converted is based on the value of the award divided by the closing value of Encana’s share price at the end of the performance period of the HPR award.
For both Directors and employees, DSUs can only be redeemed following departure from Encana in accordance with the terms of the respective DSU Plan and must be redeemed prior to December 15 th of the year following the departure from Encana.
The following table summarizes information related to the DSUs:
|
(thousands of units) |
|
|
|
|
|
Canadian Dollar Denominated Outstanding DSUs |
|
|||||
|
As at December 31 |
|
|
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, Beginning of Year |
|
|
|
|
|
|
895 |
|
|
|
920 |
|
|
Granted |
|
|
|
|
|
|
34 |
|
|
|
134 |
|
|
Converted from HPR awards |
|
|
|
|
|
|
22 |
|
|
|
16 |
|
|
Units, in Lieu of Dividends |
|
|
|
|
|
|
6 |
|
|
|
5 |
|
|
Redeemed |
|
|
|
|
|
|
(2 |
) |
|
|
(180 |
) |
|
Outstanding, End of Year |
|
|
|
|
|
|
955 |
|
|
|
895 |
|
During the year, Encana recorded a reduction of compensation costs of $6 million related to the outstanding DSUs (2017 - compensation costs of $3 million; 2016 - compensation costs of $7 million).
|
F) |
RESTRICTED SHARE UNITS |
RSUs are granted to eligible employees and commencing in 2018, to Directors. An RSU is a conditional grant to receive the equivalent of an Encana common share upon vesting of the RSUs and in accordance with the terms and conditions of the RSU Plans and grant agreements.
RSUs issued to employees vest three years from the date granted, provided the employee remains actively employed with Encana on the vesting date. RSUs issued to Directors fully vest on the grant date and have no required term of service. The RSUs issued to Directors are settled three years from the date granted or following the Director’s departure from Encana, whichever is earlier.
The Company currently settles RSUs granted to eligible employees and Directors in cash.
115
The following table summarizes information related to the RSUs:
|
(thousands of units) |
|
Canadian Dollar Denominated Outstanding RSUs |
|
|
U.S. Dollar Denominated Outstanding RSUs |
|
||||||||||
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested and Outstanding, Beginning of Year |
|
|
11,029 |
|
|
|
10,998 |
|
|
|
10,534 |
|
|
|
10,418 |
|
|
Granted |
|
|
2,582 |
|
|
|
2,411 |
|
|
|
2,742 |
|
|
|
2,434 |
|
|
Units, in Lieu of Dividends |
|
|
68 |
|
|
|
60 |
|
|
|
68 |
|
|
|
59 |
|
|
Vested and Released |
|
|
(2,551 |
) |
|
|
(2,088 |
) |
|
|
(2,266 |
) |
|
|
(1,268 |
) |
|
Forfeited |
|
|
(252 |
) |
|
|
(352 |
) |
|
|
(489 |
) |
|
|
(1,109 |
) |
|
Unvested and Outstanding, End of Year |
|
|
10,876 |
|
|
|
11,029 |
|
|
|
10,589 |
|
|
|
10,534 |
|
During the year, Encana recorded a reduction of compensation costs of $22 million related to the outstanding RSUs (2017 - compensation costs of $98 million; 2016 - compensation costs of $84 million).
As at December 31, 2018, there was approximately $30 million of unrecognized compensation costs (2017 - $99 million) related to unvested RSUs. The costs are expected to be recognized over a weighted average period of 0.8 years.
|
21. |
Pension and Other Post-Employment Benefits |
The Company sponsors defined benefit and defined contribution plans, providing pension and other post-employment benefits (“OPEB”) to its employees in Canada and the U.S. As of January 1, 2003, the defined benefit pension plan was closed to new entrants. The average remaining service period of active employees participating in the defined benefit pension plan is six years and the average remaining life expectancy of inactive employees is 14 years. The average remaining service period of the active employees participating in the OPEB plan is 13 years.
The Company is required to file an actuarial valuation of its pension plans with the provincial regulator at least every three years, or more frequently if directed by the regulator. The most recent filing was dated December 31, 2016 and the next required filing is expected to be as at December 31, 2019.
116
The following tables set forth changes in the benefit obligations and fair value of plan assets for the Company’s defined benefit pension and other post-employment benefit plans for the years ended December 31, 2018 and 2017, as well as the funded status of the plans and amounts recognized in the Consolidated Financial Statements as at December 31, 2018 and 2017.
|
|
|
Defined Benefits |
|
|
OPEB |
|
||||||||||
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Benefit Obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected Benefit Obligation, Beginning of Year |
|
$ |
226 |
|
|
$ |
211 |
|
|
$ |
85 |
|
|
$ |
92 |
|
|
Service Cost |
|
|
1 |
|
|
|
1 |
|
|
|
7 |
|
|
|
8 |
|
|
Interest Cost |
|
|
7 |
|
|
|
7 |
|
|
|
3 |
|
|
|
3 |
|
|
Actuarial (Gains) Losses |
|
|
(7 |
) |
|
|
7 |
|
|
|
(15 |
) |
|
|
(8 |
) |
|
Exchange Differences |
|
|
(17 |
) |
|
|
15 |
|
|
|
(2 |
) |
|
|
- |
|
|
Employee Contributions |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
|
Benefits Paid |
|
|
(14 |
) |
|
|
(15 |
) |
|
|
(6 |
) |
|
|
(6 |
) |
|
Curtailment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(5 |
) |
|
Projected Benefit Obligation, End of Year |
|
$ |
196 |
|
|
$ |
226 |
|
|
$ |
73 |
|
|
$ |
85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Plan Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Plan Assets, Beginning of Year |
|
$ |
210 |
|
|
$ |
194 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Actual Return on Plan Assets |
|
|
- |
|
|
|
15 |
|
|
|
- |
|
|
|
- |
|
|
Exchange Differences |
|
|
(16 |
) |
|
|
14 |
|
|
|
- |
|
|
|
- |
|
|
Employee Contributions |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
|
Employer Contributions |
|
|
2 |
|
|
|
2 |
|
|
|
5 |
|
|
|
5 |
|
|
Benefits Paid |
|
|
(14 |
) |
|
|
(15 |
) |
|
|
(6 |
) |
|
|
(6 |
) |
|
Transfers to Defined Contribution Plan |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Fair Value of Plan Assets, End of Year |
|
$ |
182 |
|
|
$ |
210 |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded Status of Plan Assets, End of Year |
|
$ |
(14 |
) |
|
$ |
(16 |
) |
|
$ |
(73 |
) |
|
$ |
(85 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Recognized Amounts in the Consolidated Balance Sheet Consist of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets |
|
$ |
4 |
|
|
$ |
4 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Current Liabilities |
|
|
- |
|
|
|
- |
|
|
|
(6 |
) |
|
|
(7 |
) |
|
Non-Current Liabilities |
|
|
(18 |
) |
|
|
(20 |
) |
|
|
(67 |
) |
|
|
(78 |
) |
|
Total |
|
$ |
(14 |
) |
|
$ |
(16 |
) |
|
$ |
(73 |
) |
|
$ |
(85 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Recognized Amounts in Accumulated Other Comprehensive Income Consist of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Actuarial (Gains) Losses |
|
$ |
28 |
|
|
$ |
28 |
|
|
$ |
(48 |
) |
|
$ |
(35 |
) |
|
Net Prior Service Costs |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(4 |
) |
|
|
(5 |
) |
|
Total Recognized in Accumulated Other Comprehensive Income, Before Tax |
|
$ |
23 |
|
|
$ |
23 |
|
|
$ |
(52 |
) |
|
$ |
(40 |
) |
The accumulated defined benefit obligation for all defined benefit plans was $267 million as at December 31, 2018 (2017 - $310 million).
The following table sets forth the defined benefit plans with accumulated benefit obligation and projected benefit obligation in excess of the fair value of the plan assets:
|
|
|
Defined Benefits |
|
|
OPEB |
|
||||||||||
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected Benefit Obligation |
|
$ |
(67 |
) |
|
$ |
(77 |
) |
|
$ |
(73 |
) |
|
$ |
(85 |
) |
|
Accumulated Benefit Obligation |
|
|
(66 |
) |
|
|
(76 |
) |
|
|
(73 |
) |
|
|
(85 |
) |
|
Fair Value of Plan Assets |
|
|
49 |
|
|
|
57 |
|
|
|
- |
|
|
|
- |
|
117
Following are the weighted average assumptions used by the Company in determining the defined benefit pension and other post-employment benefit obligations:
|
|
|
Defined Benefits |
|
|
OPEB |
|
||||||||||
|
As at December 31 |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate |
|
|
3.50 |
% |
|
|
3.25 |
% |
|
|
4.04 |
% |
|
|
3.44 |
% |
|
Rates of Increase in Compensation Levels |
|
|
3.12 |
% |
|
|
3.49 |
% |
|
|
6.27 |
% |
|
|
6.26 |
% |
The following sets forth total benefit plans expense recognized by the Company:
|
|
|
Pension Benefits |
|
|
OPEB |
|
||||||||||||||||||
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Defined Periodic Benefit Cost |
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
(1 |
) |
|
$ |
7 |
|
|
$ |
3 |
|
|
$ |
13 |
|
|
Defined Contribution Plan Expense |
|
|
24 |
|
|
|
24 |
|
|
|
25 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Total Benefit Plans Expense |
|
$ |
25 |
|
|
$ |
24 |
|
|
$ |
24 |
|
|
$ |
7 |
|
|
$ |
3 |
|
|
$ |
13 |
|
Of the total benefit plans expense, $23 million (2017 - $25 million; 2016 - $28 million) was included in operating expense and $9 million (2017 - $8 million; 2016 - $9 million) was included in administrative expense. Excluding service costs, net defined periodic benefit costs of nil (2017 - curtailment of $6 million; 2016 - nil) were recorded in other (gains) losses, net.
The net defined periodic benefit cost is as follows:
|
|
|
Defined Benefits |
|
|
OPEB |
|
||||||||||||||||||
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service Cost |
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
2 |
|
|
$ |
7 |
|
|
$ |
8 |
|
|
$ |
10 |
|
|
Interest Cost |
|
|
7 |
|
|
|
7 |
|
|
|
8 |
|
|
|
3 |
|
|
|
3 |
|
|
|
4 |
|
|
Expected Return on Plan Assets |
|
|
(8 |
) |
|
|
(9 |
) |
|
|
(11 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Amounts Reclassified from Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial (gains) and losses |
|
|
1 |
|
|
|
1 |
|
|
|
- |
|
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
Amortization of net prior service costs |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
- |
|
|
Curtailment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
|
Curtailment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(5 |
) |
|
|
- |
|
|
Total Net Defined Periodic Benefit Cost (1) |
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
(1 |
) |
|
$ |
7 |
|
|
$ |
3 |
|
|
$ |
13 |
|
|
(1) |
The components of total net defined periodic benefit cost, excluding the service cost component, are included in other (gains) losses, net. |
The amounts recognized in other comprehensive income are as follows:
|
|
|
Defined Benefits |
|
|
OPEB |
|
||||||||||||||||||
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Actuarial (Gains) Losses |
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
8 |
|
|
$ |
(15 |
) |
|
$ |
(8 |
) |
|
$ |
(14 |
) |
|
Amortization of Net Actuarial Gains and (Losses) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
- |
|
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
|
Amortization of Net Prior Service Costs |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
|
|
- |
|
|
Curtailment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
Total Amounts Recognized in Other Comprehensive (Income) Loss, Before Tax |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
8 |
|
|
$ |
(12 |
) |
|
$ |
(5 |
) |
|
$ |
(13 |
) |
|
Total Amounts Recognized in Other Comprehensive (Income) Loss, After Tax |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
6 |
|
|
$ |
(9 |
) |
|
$ |
(3 |
) |
|
$ |
(9 |
) |
The estimated net actuarial gains and net prior service costs for the pension and other post-retirement plans that will be amortized from accumulated other comprehensive income into the defined periodic benefit plan expense in 2019 is $3 million.
118
Following are the weighted average assumptions used by the Company in determining the net periodic pension and other post-retirement benefit costs:
|
|
|
Defined Benefits |
|
|
OPEB |
|
||||||||||||||||||
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount Rate |
|
|
3.25 |
% |
|
|
3.50 |
% |
|
|
3.75 |
% |
|
|
3.46 |
% |
|
|
3.76 |
% |
|
|
4.05 |
% |
|
Long-Term Rate of Return on Plan Assets |
|
|
4.25 |
% |
|
|
5.25 |
% |
|
|
6.25 |
% |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Rates of Increase in Compensation Levels |
|
|
3.49 |
% |
|
|
3.49 |
% |
|
|
3.49 |
% |
|
|
6.36 |
% |
|
|
6.10 |
% |
|
|
6.43 |
% |
The Company’s assumed health care cost trend rates are as follows:
|
For the years ended December 31 |
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health Care Cost Trend Rate for Next Year |
|
|
|
|
|
|
|
|
6.99 |
% |
|
|
6.98 |
% |
|
|
7.30 |
% |
|
Rate to Which the Cost Trend Rate is Assumed to Decline (Ultimate Trend Rate) |
|
|
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
||||
|
Year that the Rate Reaches the Ultimate Trend Rate |
|
|
|
|
|
|
|
2026 |
|
|
2025 |
|
|
2026 |
|
|||
A one percent change in the assumed health care cost trend rate over the projected period would have the following effects:
|
|
|
|
|
|
|
1% Increase |
|
|
1% Decrease |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect on Total of Service and Interest Cost Components |
|
|
|
|
|
$ |
1 |
|
|
$ |
(1 |
) |
|
Effect on Other Post-Retirement Benefit Obligations |
|
|
|
|
|
$ |
5 |
|
|
$ |
(4 |
) |
The Company expects to contribute $1 million to its defined benefit pension plans in 2019. The Company’s OPEB plans are funded on an as required basis.
The following provides an estimate of benefit payments for the next 10 years. These estimates reflect benefit increases due to continuing employee service.
|
|
|
|
|
|
|
Defined Benefit Pension Payments |
|
|
Other Benefit Payments |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
|
|
|
|
$ |
15 |
|
|
$ |
6 |
|
|
2020 |
|
|
|
|
|
|
14 |
|
|
|
6 |
|
|
2021 |
|
|
|
|
|
|
14 |
|
|
|
6 |
|
|
2022 |
|
|
|
|
|
|
14 |
|
|
|
6 |
|
|
2023 |
|
|
|
|
|
|
14 |
|
|
|
6 |
|
|
2024 - 2028 |
|
|
|
|
|
|
65 |
|
|
|
24 |
|
119
The Company’s registered and other defined benefit pension plan assets are presented by investment asset category and input level within the fair value hierarchy as follows:
|
As at December 31 |
|
2018 |
|
|||||||||||||
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
$ |
26 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
26 |
|
|
Fixed Income - Canadian Bond Funds |
|
|
- |
|
|
|
96 |
|
|
|
- |
|
|
|
96 |
|
|
Equity - International |
|
|
- |
|
|
|
60 |
|
|
|
- |
|
|
|
60 |
|
|
Fair Value of Plan Assets, End of Year |
|
$ |
26 |
|
|
$ |
156 |
|
|
$ |
- |
|
|
$ |
182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31 |
|
2017 |
|
|||||||||||||
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
$ |
27 |
|
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
28 |
|
|
Fixed Income - Canadian Bond Funds |
|
|
- |
|
|
|
67 |
|
|
|
- |
|
|
|
67 |
|
|
Equity - Domestic |
|
|
13 |
|
|
|
41 |
|
|
|
- |
|
|
|
54 |
|
|
Equity - International |
|
|
- |
|
|
|
50 |
|
|
|
- |
|
|
|
50 |
|
|
Real Estate and Other |
|
|
- |
|
|
|
- |
|
|
|
11 |
|
|
|
11 |
|
|
Fair Value of Plan Assets, End of Year |
|
$ |
40 |
|
|
$ |
159 |
|
|
$ |
11 |
|
|
$ |
210 |
|
Fixed Income investments consist of Canadian bonds issued by investment grade companies. Equity investments consist of both domestic and international securities. The fair values of these securities are based on dealer quotes, quoted market prices and net asset values. Real Estate and Other consists mainly of commercial properties and is valued based on a discounted cash flow model.
A summary in changes in Level 3 fair value measurements is presented below:
|
|
|
|
|
Real Estate and Other |
|
|||||
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
|
|
$ |
11 |
|
|
$ |
10 |
|
|
Purchases, Sales and Settlements |
|
|
|
|
|
|
|
|
|
|
|
Purchases and sales |
|
|
|
|
- |
|
|
|
- |
|
|
Settlements |
|
|
|
|
(10 |
) |
|
|
- |
|
|
Actual Return on Plan Assets |
|
|
|
|
|
|
|
|
|
|
|
Relating to assets sold during the reporting period |
|
|
|
|
(1 |
) |
|
|
- |
|
|
Relating to assets still held at the reporting date |
|
|
|
|
- |
|
|
|
1 |
|
|
Transfers In and Out of Level 3 |
|
|
|
|
- |
|
|
|
- |
|
|
Balance, End of Year |
|
|
|
$ |
- |
|
|
$ |
11 |
|
Encana’s registered pension plan assets were invested by the Company in the following as at December 31, 2018: 69 percent Bonds (2017 - 43 percent), 31 percent Foreign Equity (2017 - 23 percent), nil percent Domestic Equity (2017 - 27 percent) and nil percent Real Estate and Other (2017 - 7 percent). The expected long-term rate of return is 4 percent. The expected rate of return on pension plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The actual return on plan assets was nil (2017 - $15 million). The asset allocation structure is subject to diversification requirements and constraints, which reduce risk by limiting exposure to individual equity investment, credit rating categories and foreign currency exposure.
120
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of those instruments. Fair value information related to pension plan assets is included in Note 21.
Recurring fair value measurements are performed for risk management assets and liabilities and other derivative contracts, as discussed further in Note 23. These items are carried at fair value in the Consolidated Balance Sheet and are classified within the three levels of the fair value hierarchy in the following tables. There have been no significant transfers between the hierarchy levels during the period.
Fair value changes and settlements for amounts related to risk management assets and liabilities are recognized in revenues, transportation and processing expense, and foreign exchange gains and losses according to their purpose.
|
As at December 31, 2018 |
|
Level 1 Quoted Prices in Active Markets |
|
|
Level 2 Other Observable Inputs |
|
|
Level 3 Significant Unobservable Inputs |
|
|
Total Fair Value |
|
|
Netting (1) |
|
|
Carrying Amount |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
- |
|
|
$ |
492 |
|
|
$ |
139 |
|
|
$ |
631 |
|
|
$ |
(77 |
) |
|
$ |
554 |
|
|
Long-term assets |
|
|
- |
|
|
|
177 |
|
|
|
- |
|
|
|
177 |
|
|
|
(16 |
) |
|
|
161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
- |
|
|
$ |
81 |
|
|
$ |
- |
|
|
$ |
81 |
|
|
$ |
(77 |
) |
|
$ |
4 |
|
|
Long-term liabilities |
|
|
- |
|
|
|
38 |
|
|
|
- |
|
|
|
38 |
|
|
|
(16 |
) |
|
|
22 |
|
|
Foreign Currency Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
- |
|
|
|
21 |
|
|
|
- |
|
|
|
21 |
|
|
|
- |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Derivative Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current in accounts payable and accrued liabilities |
|
$ |
- |
|
|
$ |
4 |
|
|
$ |
- |
|
|
$ |
4 |
|
|
$ |
- |
|
|
$ |
4 |
|
|
Long-term in other liabilities and provisions |
|
|
- |
|
|
|
10 |
|
|
|
- |
|
|
|
10 |
|
|
|
- |
|
|
|
10 |
|
|
As at December 31, 2017 |
|
Level 1 Quoted Prices in Active Markets |
|
|
Level 2 Other Observable Inputs |
|
|
Level 3 Significant Unobservable Inputs |
|
|
Total Fair Value |
|
|
Netting (1) |
|
|
Carrying Amount |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
- |
|
|
$ |
189 |
|
|
$ |
- |
|
|
$ |
189 |
|
|
$ |
(15 |
) |
|
$ |
174 |
|
|
Long-term assets |
|
|
- |
|
|
|
248 |
|
|
|
- |
|
|
|
248 |
|
|
|
(2 |
) |
|
|
246 |
|
|
Foreign Currency Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
|
- |
|
|
|
31 |
|
|
|
- |
|
|
|
31 |
|
|
|
- |
|
|
|
31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
3 |
|
|
$ |
196 |
|
|
$ |
51 |
|
|
$ |
250 |
|
|
$ |
(15 |
) |
|
$ |
235 |
|
|
Long-term liabilities |
|
|
- |
|
|
|
15 |
|
|
|
- |
|
|
|
15 |
|
|
|
(2 |
) |
|
|
13 |
|
|
Foreign Currency Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Derivative Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current in accounts payable and accrued liabilities |
|
$ |
- |
|
|
$ |
5 |
|
|
$ |
- |
|
|
$ |
5 |
|
|
$ |
- |
|
|
$ |
5 |
|
|
Long-term in other liabilities and provisions |
|
|
- |
|
|
|
14 |
|
|
|
- |
|
|
|
14 |
|
|
|
- |
|
|
|
14 |
|
|
(1) |
Netting to offset derivative assets and liabilities where the legal right and intention to offset exists, or where counterparty master netting arrangements contain provisions for net settlement. |
121
The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, NYMEX costless collars, NYMEX call options, foreign currency swaps and basis swaps with terms to 2023 . Level 2 also includes financial guarantee contracts as discussed in Note 23. The fair values of these contracts are based on a market approach and are estimated using inputs which are either directly or indirectly observable at the reporting date, such as exchange and other published prices, broker quotes and observable trading activity.
Level 3 Fair Value Measurements
As at December 31, 2018, the Company’s Level 3 risk management assets and liabilities consist of WTI three-way options with terms to 2019. The WTI three-way options are a combination of a sold call, bought put and a sold put. These contracts allow the Company to participate in the upside of commodity prices to the ceiling of the call option and provide the Company with partial downside price protection through the put options. The fair values of the WTI three-way options are based on the income approach and are modelled using observable and unobservable inputs such as implied volatility. The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness.
A summary of changes in Level 3 fair value measurements is presented below:
|
|
|
|
|
|
|
Risk Management |
|
|||||
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
|
|
|
|
$ |
(51 |
) |
|
$ |
(36 |
) |
|
Total Gains (Losses) |
|
|
|
|
|
|
97 |
|
|
|
(9 |
) |
|
Purchases, Sales, Issuances and Settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases, sales and issuances |
|
|
|
|
|
|
- |
|
|
|
- |
|
|
Settlements |
|
|
|
|
|
|
93 |
|
|
|
(6 |
) |
|
Transfers Out of Level 3 (1) |
|
|
|
|
|
|
- |
|
|
|
- |
|
|
Balance, End of Year |
|
|
|
|
|
$ |
139 |
|
|
$ |
(51 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Unrealized Gains (Losses) Related to Assets and Liabilities Held at End of Year |
|
|
|
|
|
$ |
139 |
|
|
$ |
(51 |
) |
|
(1) |
The Company’s policy is to recognize transfers out of Level 3 on the date of the event of change in circumstances that caused the transfer. |
Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:
|
As at December 31 |
|
Valuation Technique |
|
Unobservable Input |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management - WTI Options |
|
Option Model |
|
Implied Volatility |
|
|
29% - 73% |
|
|
17% - 76% |
A 10 percent increase or decrease in implied volatility for the WTI options would cause a corresponding $6 million (2017 - $2 million) increase or decrease to net risk management assets and liabilities.
122
|
A) |
FINANCIAL INSTRUMENTS |
Encana’s financial assets and liabilities are recognized in cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, long-term debt, and other liabilities and provisions.
|
B) |
RISK MANAGEMENT ACTIVITIES |
Encana uses derivative financial instruments to manage its exposure to cash flow variability from commodity prices and fluctuating foreign currency exchange rates. The Company does not apply hedge accounting to any of its derivative financial instruments. As a result, gains and losses from changes in the fair value are recognized in net earnings.
COMMODITY PRICE RISK
Commodity price risk arises from the effect that fluctuations in future commodity prices may have on future cash flows. To partially mitigate exposure to commodity price risk, the Company has entered into various derivative financial instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is to not use derivative financial instruments for speculative purposes.
Crude Oil and NGLs - To partially mitigate crude oil and NGL commodity price risk, the Company uses WTI-based and Mont Belvieu-based contracts such as fixed price contracts and options. Encana has also entered into basis swaps to manage against widening price differentials between various production areas and benchmark price points.
Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses NYMEX-based contracts such as fixed price contracts, options and costless collars. Encana has also entered into basis swaps to manage against widening price differentials between various production areas and benchmark price points.
FOREIGN EXCHANGE RISK
Foreign exchange risk arises from changes in foreign currency exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at December 31, 2018, Encana has entered into $1.0 billion notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7516 to C$1, which mature monthly throughout 2019.
123
RISK MANAGEMENT POSITIONS AS AT DECEMBER 31, 2018
|
|
|
Notional Volumes |
|
Term |
|
Average Price |
|
|
Fair Value |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and NGL Contracts |
|
|
|
|
|
US$/bbl |
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Fixed Price |
|
35.0 Mbbls/d |
|
2019 |
|
|
60.31 |
|
|
$ |
163 |
|
|
Propane Fixed Price |
|
7.8 Mbbls/d |
|
2019 |
|
|
35.72 |
|
|
|
26 |
|
|
Butane Fixed Price |
|
6.5 Mbbls/d |
|
2019 |
|
|
40.54 |
|
|
|
26 |
|
|
Ethane Fixed Price |
|
5.3 Mbbls/d |
|
2019 |
|
|
17.23 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Three-Way Options |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sold call / bought put / sold put |
|
52.5 Mbbls/d |
|
2019 |
|
69.22 / 59.47 / 48.57 |
|
|
|
139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Contracts (1) |
|
|
|
2019 |
|
|
|
|
|
|
18 |
|
|
|
|
|
|
2020 |
|
|
|
|
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and NGLs Fair Value Position |
|
|
|
|
|
|
|
|
|
|
367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Contracts |
|
|
|
|
|
US$/Mcf |
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Fixed Price |
|
955 MMcf/d |
|
2019 |
|
|
2.81 |
|
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sold call / bought put |
|
70 MMcf/d |
|
Q1 2019 |
|
4.65 / 4.04 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Call Options |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sold call price |
|
230 MMcf/d |
|
2019 |
|
|
3.75 |
|
|
|
(3 |
) |
|
Bought call price |
|
230 MMcf/d |
|
2019 |
|
|
3.75 |
|
|
|
(2 |
) |
|
Sold call price |
|
230 MMcf/d |
|
2020 |
|
|
3.25 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Contracts (2) |
|
|
|
2019 |
|
|
|
|
|
|
185 |
|
|
|
|
|
|
2020 |
|
|
|
|
|
|
136 |
|
|
|
|
|
|
2021 |
|
|
|
|
|
|
11 |
|
|
|
|
|
|
2022 - 2023 |
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Fair Value Position |
|
|
|
|
|
|
|
|
|
|
326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Premiums Received on Unexpired Options |
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Derivative Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Position |
|
|
|
|
|
|
|
|
|
|
(14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Position (3) |
|
|
|
2019 |
|
|
|
|
|
|
(21 |
) |
|
Total Fair Value Position and Net Premiums Received |
|
|
|
|
|
|
|
|
|
$ |
654 |
|
|
(1) |
Encana has entered into Midland, Magellan East Houston and Brent differential swaps to WTI. |
|
(2) |
Encana has entered into swaps to protect against weakening AECO, Dawn, Chicago, Malin and Waha basis to NYMEX. |
|
(3) |
Encana has entered into U.S. dollar denominated fixed-for-floating average currency swaps to protect against fluctuations between the Canadian and U.S. dollars. |
124
EARNINGS IMPACT OF REALIZED AND UNREALIZED GAINS (LOSSES) ON RISK MANAGEMENT POSITIONS
|
For the years ended December 31 |
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gains (Losses) on Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity and Other Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1) |
|
|
|
$ |
(104 |
) |
|
$ |
40 |
|
|
$ |
361 |
|
|
Transportation and processing |
|
|
|
|
- |
|
|
|
(4 |
) |
|
|
(8 |
) |
|
Foreign Currency Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange |
|
|
|
|
10 |
|
|
|
15 |
|
|
|
- |
|
|
|
|
|
|
$ |
(94 |
) |
|
$ |
51 |
|
|
$ |
353 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Gains (Losses) on Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity and Other Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (2) |
|
|
|
$ |
519 |
|
|
$ |
442 |
|
|
$ |
(636 |
) |
|
Transportation and processing |
|
|
|
|
- |
|
|
|
- |
|
|
|
22 |
|
|
Foreign Currency Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange |
|
|
|
|
(51 |
) |
|
|
32 |
|
|
|
(1 |
) |
|
|
|
|
|
$ |
468 |
|
|
$ |
474 |
|
|
$ |
(615 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Realized and Unrealized Gains (Losses) on Risk Management, net |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Commodity and Other Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1) (2) |
|
|
|
$ |
415 |
|
|
$ |
482 |
|
|
$ |
(275 |
) |
|
Transportation and processing |
|
|
|
|
- |
|
|
|
(4 |
) |
|
|
14 |
|
|
Foreign Currency Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange |
|
|
|
|
(41 |
) |
|
|
47 |
|
|
|
(1 |
) |
|
|
|
|
|
$ |
374 |
|
|
$ |
525 |
|
|
$ |
(262 |
) |
|
(1) |
Includes a realized gain of $7 million for the year ended December 31, 2018 (2017 - gain of $7 million; 2016 - gain of $6 million) related to other derivative contracts. |
|
(2) |
Includes an unrealized loss of $2 million for the year ended December 31, 2018 (2017 - loss of $2 million; 2016 - gain of $5 million) related to other derivative contracts. |
RECONCILIATION OF UNREALIZED RISK MANAGEMENT POSITIONS FROM JANUARY 1 TO DECEMBER 31
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||||||
|
|
|
Fair Value |
|
|
Total Unrealized Gain (Loss) |
|
|
Total Unrealized Gain (Loss) |
|
|
Total Unrealized Gain (Loss) |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts, Beginning of Year |
|
$ |
183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Year |
|
|
374 |
|
|
$ |
374 |
|
|
$ |
525 |
|
|
$ |
(262 |
) |
|
Settlement of Other Derivative Contracts |
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts Realized During the Year |
|
|
94 |
|
|
|
94 |
|
|
|
(51 |
) |
|
|
(353 |
) |
|
Fair Value of Contracts Outstanding |
|
$ |
658 |
|
|
$ |
468 |
|
|
$ |
474 |
|
|
$ |
(615 |
) |
|
Net Premiums Received on Unexpired Options |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts and Net Premiums Received, End of Year |
|
$ |
654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value. See Note 22 for a discussion of fair value measurements.
125
UNREALIZED RISK MANAGEMENT POSITIONS
|
As at December 31 |
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
|
Current |
|
$ |
554 |
|
|
$ |
205 |
|
|
Long-term |
|
|
161 |
|
|
|
246 |
|
|
|
|
|
715 |
|
|
|
451 |
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
Current |
|
|
25 |
|
|
|
236 |
|
|
Long-term |
|
|
22 |
|
|
|
13 |
|
|
|
|
|
47 |
|
|
|
249 |
|
|
|
|
|
|
|
|
|
|
|
|
Other Derivative Contracts |
|
|
|
|
|
|
|
|
|
Current in accounts payable and accrued liabilities |
|
|
4 |
|
|
|
5 |
|
|
Long-term in other liabilities and provisions |
|
|
10 |
|
|
|
14 |
|
|
Net Risk Management Assets (Liabilities) and Other Derivative Contracts |
|
$ |
654 |
|
|
$ |
183 |
|
SUMMARY OF UNREALIZED RISK MANAGEMENT POSITIONS
|
As at December 31 |
|
2018 |
|
|
2017 |
|
||||||||||||||||||
|
|
|
Risk Management |
|
|
Risk Management |
|
||||||||||||||||||
|
|
|
Asset |
|
|
Liability |
|
|
Net |
|
|
Asset |
|
|
Liability |
|
|
Net |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Positions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and NGLs |
|
$ |
380 |
|
|
$ |
13 |
|
|
$ |
367 |
|
|
$ |
- |
|
|
$ |
244 |
|
|
$ |
(244 |
) |
|
Natural gas |
|
|
335 |
|
|
|
13 |
|
|
|
322 |
|
|
|
420 |
|
|
|
4 |
|
|
|
416 |
|
|
Other Positions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other derivative contracts |
|
|
- |
|
|
|
14 |
|
|
|
(14 |
) |
|
|
- |
|
|
|
19 |
|
|
|
(19 |
) |
|
Foreign currency contracts |
|
|
- |
|
|
|
21 |
|
|
|
(21 |
) |
|
|
31 |
|
|
|
1 |
|
|
|
30 |
|
|
Total Fair Value Position |
|
$ |
715 |
|
|
$ |
61 |
|
|
$ |
654 |
|
|
$ |
451 |
|
|
$ |
268 |
|
|
$ |
183 |
|
|
C) |
CREDIT RISK |
Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. While exchange-traded contracts are subject to nominal credit risk due to the financial safeguards established by the NYSE and the TSX, over-the-counter traded contracts expose Encana to counterparty credit risk. This credit risk exposure is mitigated through the use of credit policies approved by the Board of Directors governing the Company’s credit portfolio including credit practices that limit transactions according to counterparties’ credit quality. Mitigation strategies may include master netting arrangements, requesting collateral and/or transacting credit derivatives. The Company executes commodity derivative financial instruments under master agreements that have netting provisions that provide for offsetting payables against receivables. As a result of netting provisions, the Company’s maximum exposure to loss under derivative financial instruments due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts, as disclosed in Note 22. As at December 31, 2018, the Company had no significant credit derivatives in place and held no collateral.
As at December 31, 2018, cash equivalents include high-grade, short-term securities, placed primarily with financial institutions and companies with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions that have investment grade credit ratings.
A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2018, approximately 97 percent (2017 - 92 percent) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.
126
As at December 31, 2018, Encana had four counterparties whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. These counterparties accounted for 30 percent, 13 percent, 12 percent and 10 percent of the fair value of the outstanding in-the-money net risk management contracts. As at December 31, 2017, Encana had three counterparties whose net settlement position accounted for 56 percent, 11 percent and 11 percent of the fair value of the outstanding in-the-money net risk management contracts.
During 2015 and 2017, Encana entered into agreements resulting from divestitures, which may require Encana to fulfill certain payment obligations on the take or pay volume commitments assumed by the purchasers. The circumstances that would require Encana to perform under the agreements include events where a purchaser fails to make payment to the guaranteed party and/or a purchaser is subject to an insolvency event. The agreements have remaining terms from three to six years with a fair value recognized of $14 million as at December 31, 2018 (2017 - $19 million). The maximum potential amount of undiscounted future payments is $228 million as at December 31, 2018, and is considered unlikely.
|
24. |
Supplementary Information |
Supplemental disclosures to the Consolidated Statement of Cash Flows are presented below:
|
A) |
NET CHANGE IN NON-CASH WORKING CAPITAL |
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable and accrued revenues |
|
$ |
(150 |
) |
|
$ |
(21 |
) |
|
$ |
86 |
|
|
Accounts payable and accrued liabilities |
|
|
141 |
|
|
|
(226 |
) |
|
|
(233 |
) |
|
Income tax receivable and payable |
|
|
254 |
|
|
|
(6 |
) |
|
|
(40 |
) |
|
|
|
$ |
245 |
|
|
$ |
(253 |
) |
|
$ |
(187 |
) |
|
B) |
NON-CASH ACTIVITIES |
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation incurred (See Note 15) |
|
$ |
17 |
|
|
$ |
11 |
|
|
$ |
18 |
|
|
Asset retirement obligation change in estimated future cash outflows (See Note 15) |
|
|
(20 |
) |
|
|
88 |
|
|
|
(99 |
) |
|
Property, plant and equipment accruals |
|
|
(16 |
) |
|
|
19 |
|
|
|
5 |
|
|
Capitalized long-term incentives |
|
|
(47 |
) |
|
|
55 |
|
|
|
40 |
|
|
Property additions/dispositions (swaps) |
|
|
210 |
|
|
|
194 |
|
|
|
100 |
|
|
Non-Cash Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares issued under dividend reinvestment plan (See Note 16) |
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
1 |
|
|
C) |
SUPPLEMENTARY CASH FLOW INFORMATION |
|
For the years ended December 31 |
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Paid |
|
$ |
367 |
|
|
$ |
370 |
|
|
$ |
397 |
|
|
Income Taxes (Recovered), net of Amounts Paid |
|
$ |
(246 |
) |
|
$ |
(77 |
) |
|
$ |
(19 |
) |
127
COMMITMENTS
The following table outlines the Company’s commitments as at December 31, 2018:
|
|
|
Expected Future Payments |
|
|||||||||||||||||||||||||
|
(undiscounted) |
|
2019 |
|
|
2020 |
|
|
2021 |
|
|
2022 |
|
|
2023 |
|
|
Thereafter |
|
|
Total |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
$ |
685 |
|
|
$ |
677 |
|
|
$ |
582 |
|
|
$ |
555 |
|
|
$ |
453 |
|
|
$ |
2,220 |
|
|
$ |
5,172 |
|
|
Drilling and Field Services |
|
|
128 |
|
|
|
34 |
|
|
|
10 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
172 |
|
|
Building Leases |
|
|
17 |
|
|
|
16 |
|
|
|
16 |
|
|
|
16 |
|
|
|
15 |
|
|
|
35 |
|
|
|
115 |
|
|
Total |
|
$ |
830 |
|
|
$ |
727 |
|
|
$ |
608 |
|
|
$ |
571 |
|
|
$ |
468 |
|
|
$ |
2,255 |
|
|
$ |
5,459 |
|
Included within transportation and processing in the table above are certain commitments associated with midstream service agreements with VMLP as described in Note 18. Divestiture transactions can reduce certain commitments disclosed above.
Operating lease expense recorded in the Consolidated Statement of Earnings was $83 million for the year ended December 31, 2018 (2017 - $80 million; 2016 - $82 million).
CONTINGENCIES
Encana is involved in various legal claims and actions arising in the normal course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encana’s financial position, cash flows or results of operations. Management’s assessment of these matters may change in the future as certain of these matters are in early stages or are subject to a number of uncertainties. For material matters that the Company believes an unfavourable outcome is reasonably possible, the Company discloses the nature and a range of potential exposures. If an unfavourable outcome were to occur, there exists the possibility of a material impact on the Company’s consolidated net earnings or loss for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. Such accruals are based on the Company’s information known about the matters, estimates of the outcomes of such matters and experience in handling similar matters.
|
2 6 . |
Subsequent Events |
Acquisition of Newfield Exploration Company
On February 13, 2019, Encana completed the acquisition of all the issued and outstanding shares of common stock of Newfield whereby Encana issued approximately 543.4 million common shares to Newfield shareholders, representing an exchange ratio of 2.6719 Encana common shares for each share of Newfield common stock held. Following the acquisition, Newfield’s senior notes totaling $2.45 billion remain outstanding. Newfield’s operations are focused on the development of oil-rich properties primarily located in the Anadarko Basin in Oklahoma. The post-acquisition results of operations of Newfield will be included in the Company’s interim consolidated results for the period ended March 31, 2019.
128
The unaudited supplementary information on oil and gas exploration and production activities for 2018, 2017 and 2016 has been presented in accordance with the FASB’s ASC Topic 932, “Extractive Activities - Oil and Gas” and the SEC’s final rule, “Modernization of Oil and Gas Reporting”. Disclosures by geographic area include Canada and the United States.
Proved Oil and Gas Reserves
The following reserves disclosures reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests of oil, NGLs and natural gas owned at each year end and changes in proved reserves during each of the last three years.
The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, commodity prices, economic conditions, and government restrictions. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
The following reference prices were utilized in the determination of reserves and future net revenue:
|
|
|
Oil & NGLs |
|
|
Natural Gas |
|
||||||||||
|
|
|
WTI ($/bbl) |
|
|
Edmonton Condensate (C$/bbl) |
|
|
Henry Hub ($/MMBtu) |
|
|
AECO (C$/MMBtu) |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves Pricing (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 |
|
|
65.56 |
|
|
|
79.59 |
|
|
|
3.10 |
|
|
|
1.49 |
|
|
2017 |
|
|
51.34 |
|
|
|
67.65 |
|
|
|
2.98 |
|
|
|
2.32 |
|
|
2016 |
|
|
42.75 |
|
|
|
55.39 |
|
|
|
2.49 |
|
|
|
2.17 |
|
|
(1) |
All prices were held constant in all future years when estimating net revenues and reserves. |
129
(12-MONTH AVERAGE TRAILING PRICES)
|
|
Oil (MMbbls) |
|
|
NGLs (MMbbls) |
|
|
Natural Gas (Bcf) |
|
|
Total (MMBOE) |
|
||||||||||||||||||||||||||||
|
|
Canada |
|
|
United States |
|
|
Total |
|
|
Canada |
|
|
United States |
|
|
Total |
|
|
Canada |
|
|
United States |
|
|
Total |
|
|
|
|
|
|||||||||
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
6.4 |
|
|
|
157.9 |
|
|
|
164.3 |
|
|
|
62.8 |
|
|
|
61.7 |
|
|
|
124.5 |
|
|
|
1,952 |
|
|
|
1,112 |
|
|
|
3,064 |
|
|
|
799.4 |
|
|
Revisions and improved recovery (2) |
|
(0.3 |
) |
|
|
(15.6 |
) |
|
|
(15.9 |
) |
|
|
(6.4 |
) |
|
|
(1.6 |
) |
|
|
(8.0 |
) |
|
|
(422 |
) |
|
|
177 |
|
|
|
(244 |
) |
|
|
(64.7 |
) |
|
Extensions and discoveries |
|
- |
|
|
|
52.2 |
|
|
|
52.2 |
|
|
|
58.1 |
|
|
|
17.7 |
|
|
|
75.8 |
|
|
|
796 |
|
|
|
91 |
|
|
|
887 |
|
|
|
275.7 |
|
|
Purchase of reserves in place |
|
- |
|
|
|
9.6 |
|
|
|
9.6 |
|
|
|
- |
|
|
|
2.6 |
|
|
|
2.6 |
|
|
|
- |
|
|
|
16 |
|
|
|
16 |
|
|
|
14.9 |
|
|
Sale of reserves in place |
|
(5.4 |
) |
|
|
(22.2 |
) |
|
|
(27.6 |
) |
|
|
(11.3 |
) |
|
|
(15.5 |
) |
|
|
(26.8 |
) |
|
|
(163 |
) |
|
|
(150 |
) |
|
|
(313 |
) |
|
|
(106.5 |
) |
|
Production |
|
(0.7 |
) |
|
|
(26.2 |
) |
|
|
(27.0 |
) |
|
|
(9.2 |
) |
|
|
(8.5 |
) |
|
|
(17.7 |
) |
|
|
(354 |
) |
|
|
(153 |
) |
|
|
(506 |
) |
|
|
(129.1 |
) |
|
End of year |
|
- |
|
|
|
155.6 |
|
|
|
155.6 |
|
|
|
94.0 |
|
|
|
56.4 |
|
|
|
150.4 |
|
|
|
1,810 |
|
|
|
1,093 |
|
|
|
2,902 |
|
|
|
789.7 |
|
|
Developed |
|
- |
|
|
|
82.5 |
|
|
|
82.5 |
|
|
|
25.6 |
|
|
|
31.8 |
|
|
|
57.4 |
|
|
|
903 |
|
|
|
951 |
|
|
|
1,853 |
|
|
|
448.8 |
|
|
Undeveloped |
|
- |
|
|
|
73.1 |
|
|
|
73.1 |
|
|
|
68.4 |
|
|
|
24.6 |
|
|
|
93.0 |
|
|
|
907 |
|
|
|
142 |
|
|
|
1,049 |
|
|
|
341.0 |
|
|
Total |
|
- |
|
|
|
155.6 |
|
|
|
155.6 |
|
|
|
94.0 |
|
|
|
56.4 |
|
|
|
150.4 |
|
|
|
1,810 |
|
|
|
1,093 |
|
|
|
2,902 |
|
|
|
789.7 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
- |
|
|
|
155.6 |
|
|
|
155.6 |
|
|
|
94.0 |
|
|
|
56.4 |
|
|
|
150.4 |
|
|
|
1,810 |
|
|
|
1,093 |
|
|
|
2,902 |
|
|
|
789.7 |
|
|
Revisions and improved recovery (2) |
|
0.2 |
|
|
|
(16.0 |
) |
|
|
(15.8 |
) |
|
|
(14.6 |
) |
|
|
(3.6 |
) |
|
|
(18.1 |
) |
|
|
(31 |
) |
|
|
(27 |
) |
|
|
(58 |
) |
|
|
(43.6 |
) |
|
Extensions and discoveries |
|
0.2 |
|
|
|
84.9 |
|
|
|
85.1 |
|
|
|
46.4 |
|
|
|
26.5 |
|
|
|
72.9 |
|
|
|
727 |
|
|
|
144 |
|
|
|
871 |
|
|
|
303.1 |
|
|
Purchase of reserves in place |
|
- |
|
|
|
0.8 |
|
|
|
0.8 |
|
|
|
- |
|
|
|
0.4 |
|
|
|
0.4 |
|
|
|
- |
|
|
|
2 |
|
|
|
2 |
|
|
|
1.5 |
|
|
Sale of reserves in place |
|
- |
|
|
|
(5.4 |
) |
|
|
(5.4 |
) |
|
|
(0.2 |
) |
|
|
(3.6 |
) |
|
|
(3.8 |
) |
|
|
(65 |
) |
|
|
(729 |
) |
|
|
(795 |
) |
|
|
(141.6 |
) |
|
Production |
|
(0.2 |
) |
|
|
(27.7 |
) |
|
|
(27.8 |
) |
|
|
(10.6 |
) |
|
|
(8.7 |
) |
|
|
(19.3 |
) |
|
|
(306 |
) |
|
|
(97 |
) |
|
|
(403 |
) |
|
|
(114.3 |
) |
|
End of year |
|
0.2 |
|
|
|
192.3 |
|
|
|
192.5 |
|
|
|
115.0 |
|
|
|
67.5 |
|
|
|
182.5 |
|
|
|
2,135 |
|
|
|
384 |
|
|
|
2,519 |
|
|
|
794.9 |
|
|
Developed |
|
0.2 |
|
|
|
104.7 |
|
|
|
104.9 |
|
|
|
40.5 |
|
|
|
41.6 |
|
|
|
82.1 |
|
|
|
1,082 |
|
|
|
243 |
|
|
|
1,325 |
|
|
|
407.8 |
|
|
Undeveloped |
|
- |
|
|
|
87.7 |
|
|
|
87.7 |
|
|
|
74.5 |
|
|
|
25.8 |
|
|
|
100.3 |
|
|
|
1,053 |
|
|
|
141 |
|
|
|
1,195 |
|
|
|
387.1 |
|
|
Total |
|
0.2 |
|
|
|
192.3 |
|
|
|
192.5 |
|
|
|
115.0 |
|
|
|
67.5 |
|
|
|
182.5 |
|
|
|
2,135 |
|
|
|
384 |
|
|
|
2,519 |
|
|
|
794.9 |
|
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
0.2 |
|
|
|
192.3 |
|
|
|
192.5 |
|
|
|
115.0 |
|
|
|
67.5 |
|
|
|
182.5 |
|
|
|
2,135 |
|
|
|
384 |
|
|
|
2,519 |
|
|
|
794.9 |
|
|
Revisions and improved recovery (2) |
|
0.2 |
|
|
|
19.5 |
|
|
|
19.7 |
|
|
|
(17.4 |
) |
|
|
14.2 |
|
|
|
(3.2 |
) |
|
|
249 |
|
|
|
37 |
|
|
|
285 |
|
|
|
64.1 |
|
|
Extensions and discoveries |
|
- |
|
|
|
162.4 |
|
|
|
162.4 |
|
|
|
78.9 |
|
|
|
48.6 |
|
|
|
127.4 |
|
|
|
885 |
|
|
|
233 |
|
|
|
1,118 |
|
|
|
476.2 |
|
|
Purchase of reserves in place |
|
- |
|
|
|
21.3 |
|
|
|
21.3 |
|
|
|
- |
|
|
|
7.7 |
|
|
|
7.7 |
|
|
|
- |
|
|
|
39 |
|
|
|
39 |
|
|
|
35.5 |
|
|
Sale of reserves in place |
|
- |
|
|
|
(11.4 |
) |
|
|
(11.4 |
) |
|
|
- |
|
|
|
(5.1 |
) |
|
|
(5.1 |
) |
|
|
- |
|
|
|
(40 |
) |
|
|
(40 |
) |
|
|
(23.1 |
) |
|
Production |
|
(0.1 |
) |
|
|
(32.7 |
) |
|
|
(32.8 |
) |
|
|
(18.0 |
) |
|
|
(10.6 |
) |
|
|
(28.5 |
) |
|
|
(368 |
) |
|
|
(55 |
) |
|
|
(423 |
) |
|
|
(131.9 |
) |
|
End of year |
|
0.2 |
|
|
|
351.5 |
|
|
|
351.8 |
|
|
|
158.5 |
|
|
|
122.3 |
|
|
|
280.8 |
|
|
|
2,901 |
|
|
|
598 |
|
|
|
3,499 |
|
|
|
1,215.7 |
|
|
Developed |
|
0.2 |
|
|
|
150.6 |
|
|
|
150.9 |
|
|
|
60.8 |
|
|
|
59.4 |
|
|
|
120.2 |
|
|
|
1,707 |
|
|
|
295 |
|
|
|
2,002 |
|
|
|
604.7 |
|
|
Undeveloped |
|
- |
|
|
|
200.9 |
|
|
|
200.9 |
|
|
|
97.8 |
|
|
|
62.8 |
|
|
|
160.6 |
|
|
|
1,195 |
|
|
|
302 |
|
|
|
1,497 |
|
|
|
611.0 |
|
|
Total |
|
0.2 |
|
|
|
351.5 |
|
|
|
351.8 |
|
|
|
158.5 |
|
|
|
122.3 |
|
|
|
280.8 |
|
|
|
2,901 |
|
|
|
598 |
|
|
|
3,499 |
|
|
|
1,215.7 |
|
|
(1) |
Numbers may not add due to rounding. |
|
(2) |
Changes in reserve estimates resulting from application of improved recovery techniques are nil and are included in revisions of previous estimates. |
Definitions:
|
a. |
“Proved” oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. |
|
b. |
“Developed” oil and gas reserves are reserves of any category that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. |
|
c. |
“Undeveloped” oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. |
130
Total Proved reserves increased 420.8 MMBOE in 2018 due to the following:
|
|
• |
Revisions and improved recovery of oil, NGLs and natural gas were 64.1 MMBOE primarily due to positive forecast changes of 133.7 MMBOE and higher 12-month average trailing oil and NGL prices of 9.4 MMBOE, partially offset by proved reserves removed due to changes in the approved development plan of 79.0 MMBOE. |
|
|
• |
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 476.2 MMBOE due to the extension of proved acreage primarily from successful drilling and delineation in the Permian, Montney, Eagle Ford and Duvernay assets. |
|
|
• |
Purchases of 35.5 MMBOE were primarily in the Permian asset. |
|
|
• |
Sale of reserves in place decreased proved developed reserves by 23.1 MMBOE primarily due to the divestiture of the San Juan assets located in northwestern New Mexico. |
Total Proved reserves increased 5.2 MMBOE in 2017 due to the following:
|
|
• |
Revisions and improved recovery of oil, NGLs and natural gas were negative primarily due to negative revisions of 83.3 MMBOE resulting from changes in the approved development plan, which was partially offset by positive revisions of 32.6 MMBOE due to higher 12-month average trailing oil, NGL and natural gas prices. |
|
|
• |
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 303.1 MMBOE due to the extension of proved acreage primarily from successful drilling in the Permian, Montney and Eagle Ford assets. |
|
|
• |
Sale of reserves in place decreased proved developed reserves by 141.6 MMBOE primarily due to the divestiture of the Piceance assets located in northwestern Colorado. |
Total Proved reserves decreased 9.7 MMBOE in 2016 due to the following:
|
|
• |
Revisions and improved recovery of oil and NGLs included reductions of 6.5 MMbbls and 6.6 MMbbls, respectively, due to lower 12-month average trailing oil and NGL prices. Revisions and improved recovery of natural gas included a reduction of 462 Bcf due to a lower 12-month average trailing natural gas price. |
|
|
• |
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 275.7 MMBOE due to the extension of proved acreage primarily from successful drilling in the Permian and Montney assets. |
|
|
• |
Sale of reserves in place decreased proved developed reserves by 65.4 MMBOE and proved undeveloped reserves by 41.2 MMBOE due to the divestitures of the DJ Basin assets located in northern Colorado and the Gordondale assets located in northwestern Alberta. |
131
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
In calculating the standardized measure of discounted future net cash flows, constant price and cost assumptions were applied to Encana’s annual future production from proved reserves to determine cash inflows. Estimates of future net cash flows from proved reserves are computed based on the average beginning-of-the-month prices during the 12-month period for the year. Future production and development costs include estimates for abandonment and dismantlement costs associated with asset retirement obligations and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The effect of tax credits is also considered in determining the income tax expense. The discount was computed by application of a 10 percent discount factor to the future net cash flows.
Encana cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of Encana’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in oil and natural gas prices, development, asset retirement and production costs, and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates.
|
|
|
Canada |
|
|
United States |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
$ |
12,463 |
|
|
$ |
7,850 |
|
|
$ |
5,341 |
|
|
$ |
26,305 |
|
|
$ |
11,459 |
|
|
$ |
8,537 |
|
|
Less future: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
|
5,231 |
|
|
|
3,516 |
|
|
|
2,876 |
|
|
|
6,399 |
|
|
|
3,661 |
|
|
|
3,539 |
|
|
Development costs |
|
|
2,641 |
|
|
|
2,058 |
|
|
|
1,949 |
|
|
|
4,751 |
|
|
|
3,042 |
|
|
|
2,805 |
|
|
Income taxes |
|
|
586 |
|
|
|
76 |
|
|
|
- |
|
|
|
1,673 |
|
|
|
- |
|
|
|
- |
|
|
Future net cash flows |
|
|
4,005 |
|
|
|
2,200 |
|
|
|
516 |
|
|
|
13,482 |
|
|
|
4,756 |
|
|
|
2,193 |
|
|
Less 10% annual discount for estimated timing of cash flows |
|
|
1,351 |
|
|
|
618 |
|
|
|
77 |
|
|
|
6,532 |
|
|
|
2,025 |
|
|
|
957 |
|
|
Discounted future net cash flows |
|
$ |
2,654 |
|
|
$ |
1,582 |
|
|
$ |
439 |
|
|
$ |
6,950 |
|
|
$ |
2,731 |
|
|
$ |
1,236 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|||||||||
|
|
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
|
|
|
|
|
|
$ |
38,768 |
|
|
$ |
19,309 |
|
|
$ |
13,878 |
|
|
Less future: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
|
|
|
|
|
|
|
11,630 |
|
|
|
7,177 |
|
|
|
6,415 |
|
|
Development costs |
|
|
|
|
|
|
|
|
7,392 |
|
|
|
5,100 |
|
|
|
4,754 |
|
|
Income taxes |
|
|
|
|
|
|
|
|
2,259 |
|
|
|
76 |
|
|
|
- |
|
|
Future net cash flows |
|
|
|
|
|
|
|
|
17,487 |
|
|
|
6,956 |
|
|
|
2,709 |
|
|
Less 10% annual discount for estimated timing of cash flows |
|
|
|
|
|
|
|
|
7,883 |
|
|
|
2,643 |
|
|
|
1,034 |
|
|
Discounted future net cash flows |
|
|
|
|
|
|
|
$ |
9,604 |
|
|
$ |
4,313 |
|
|
$ |
1,675 |
|
132
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
|
|
|
Canada |
|
|
United States |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
1,582 |
|
|
$ |
439 |
|
|
$ |
635 |
|
|
$ |
2,731 |
|
|
$ |
1,236 |
|
|
$ |
1,413 |
|
|
Changes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced during the year |
|
|
(859 |
) |
|
|
(471 |
) |
|
|
(316 |
) |
|
|
(1,753 |
) |
|
|
(1,291 |
) |
|
|
(1,040 |
) |
|
Discoveries and extensions, net of related costs |
|
|
1,130 |
|
|
|
582 |
|
|
|
211 |
|
|
|
3,300 |
|
|
|
1,141 |
|
|
|
267 |
|
|
Purchases of proved reserves in place |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
468 |
|
|
|
13 |
|
|
|
47 |
|
|
Sales and transfers of proved reserves in place |
|
|
- |
|
|
|
(12 |
) |
|
|
(71 |
) |
|
|
(202 |
) |
|
|
(413 |
) |
|
|
(220 |
) |
|
Net change in prices and production costs |
|
|
407 |
|
|
|
893 |
|
|
|
20 |
|
|
|
1,642 |
|
|
|
2,183 |
|
|
|
325 |
|
|
Revisions to quantity estimates |
|
|
121 |
|
|
|
(22 |
) |
|
|
(124 |
) |
|
|
526 |
|
|
|
(203 |
) |
|
|
39 |
|
|
Accretion of discount |
|
|
164 |
|
|
|
44 |
|
|
|
64 |
|
|
|
273 |
|
|
|
124 |
|
|
|
141 |
|
|
Development costs incurred during the period |
|
|
665 |
|
|
|
454 |
|
|
|
286 |
|
|
|
1,315 |
|
|
|
1,366 |
|
|
|
873 |
|
|
Changes in estimated future development costs |
|
|
(303 |
) |
|
|
(279 |
) |
|
|
(304 |
) |
|
|
(824 |
) |
|
|
(1,433 |
) |
|
|
(456 |
) |
|
Other |
|
|
15 |
|
|
|
7 |
|
|
|
38 |
|
|
|
16 |
|
|
|
8 |
|
|
|
(153 |
) |
|
Net change in income taxes |
|
|
(268 |
) |
|
|
(53 |
) |
|
|
- |
|
|
|
(542 |
) |
|
|
- |
|
|
|
- |
|
|
Balance, end of year |
|
$ |
2,654 |
|
|
$ |
1,582 |
|
|
$ |
439 |
|
|
$ |
6,950 |
|
|
$ |
2,731 |
|
|
$ |
1,236 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|||||||||
|
|
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
|
|
|
|
|
$ |
4,313 |
|
|
$ |
1,675 |
|
|
$ |
2,048 |
|
|
Changes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced during the year |
|
|
|
|
|
|
|
|
(2,612 |
) |
|
|
(1,762 |
) |
|
|
(1,356 |
) |
|
Discoveries and extensions, net of related costs |
|
|
|
|
|
|
|
|
4,430 |
|
|
|
1,723 |
|
|
|
478 |
|
|
Purchases of proved reserves in place |
|
|
|
|
|
|
|
|
468 |
|
|
|
13 |
|
|
|
47 |
|
|
Sales and transfers of proved reserves in place |
|
|
|
|
|
|
|
|
(202 |
) |
|
|
(425 |
) |
|
|
(291 |
) |
|
Net change in prices and production costs |
|
|
|
|
|
|
|
|
2,049 |
|
|
|
3,076 |
|
|
|
345 |
|
|
Revisions to quantity estimates |
|
|
|
|
|
|
|
|
647 |
|
|
|
(225 |
) |
|
|
(85 |
) |
|
Accretion of discount |
|
|
|
|
|
|
|
|
437 |
|
|
|
168 |
|
|
|
205 |
|
|
Development costs incurred during the period |
|
|
|
|
|
|
|
|
1,980 |
|
|
|
1,820 |
|
|
|
1,159 |
|
|
Changes in estimated future development costs |
|
|
|
|
|
|
|
|
(1,127 |
) |
|
|
(1,712 |
) |
|
|
(760 |
) |
|
Other |
|
|
|
|
|
|
|
|
31 |
|
|
|
15 |
|
|
|
(115 |
) |
|
Net change in income taxes |
|
|
|
|
|
|
|
|
(810 |
) |
|
|
(53 |
) |
|
|
- |
|
|
Balance, end of year |
|
|
|
|
|
|
|
$ |
9,604 |
|
|
$ |
4,313 |
|
|
$ |
1,675 |
|
133
The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities.
|
|
|
Canada |
|
|
United States |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, NGL and natural gas revenues, net of transportation and processing |
|
$ |
993 |
|
|
$ |
613 |
|
|
$ |
491 |
|
|
$ |
2,189 |
|
|
$ |
1,714 |
|
|
$ |
1,510 |
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs, production, mineral and other taxes, and accretion of asset retirement obligation |
|
|
157 |
|
|
|
164 |
|
|
|
197 |
|
|
|
445 |
|
|
|
438 |
|
|
|
499 |
|
|
Depreciation, depletion and amortization |
|
|
361 |
|
|
|
236 |
|
|
|
260 |
|
|
|
860 |
|
|
|
530 |
|
|
|
523 |
|
|
Impairments |
|
|
- |
|
|
|
- |
|
|
|
493 |
|
|
|
- |
|
|
|
- |
|
|
|
903 |
|
|
Operating income (loss) |
|
|
475 |
|
|
|
213 |
|
|
|
(459 |
) |
|
|
884 |
|
|
|
746 |
|
|
|
(415 |
) |
|
Income taxes |
|
|
128 |
|
|
|
58 |
|
|
|
(123 |
) |
|
|
191 |
|
|
|
161 |
|
|
|
(150 |
) |
|
Results of operations |
|
$ |
347 |
|
|
$ |
155 |
|
|
$ |
(336 |
) |
|
$ |
693 |
|
|
$ |
585 |
|
|
$ |
(265 |
) |
|
|
|
|
|
|
|
|
|
Total |
|
|||||||||
|
|
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, NGL and natural gas revenues, net of transportation and processing |
|
|
|
|
|
|
|
$ |
3,182 |
|
|
$ |
2,327 |
|
|
$ |
2,001 |
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs, production, mineral and other taxes, and accretion of asset retirement obligation |
|
|
|
|
|
|
|
|
602 |
|
|
|
602 |
|
|
|
696 |
|
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
1,221 |
|
|
|
766 |
|
|
|
783 |
|
|
Impairments |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
1,396 |
|
|
Operating income (loss) |
|
|
|
|
|
|
|
|
1,359 |
|
|
|
959 |
|
|
|
(874 |
) |
|
Income taxes |
|
|
|
|
|
|
|
|
319 |
|
|
|
219 |
|
|
|
(273 |
) |
|
Results of operations |
|
|
|
|
|
|
|
$ |
1,040 |
|
|
$ |
740 |
|
|
$ |
(601 |
) |
CAPITALIZED COSTS
Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified.
|
|
|
Canada |
|
|
United States |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties |
|
$ |
13,996 |
|
|
$ |
14,555 |
|
|
$ |
13,159 |
|
|
$ |
27,189 |
|
|
$ |
25,610 |
|
|
$ |
26,393 |
|
|
Unproved oil and gas properties |
|
|
237 |
|
|
|
311 |
|
|
|
285 |
|
|
|
3,493 |
|
|
|
4,169 |
|
|
|
4,913 |
|
|
Total capital cost |
|
|
14,233 |
|
|
|
14,866 |
|
|
|
13,444 |
|
|
|
30,682 |
|
|
|
29,779 |
|
|
|
31,306 |
|
|
Accumulated DD&A |
|
|
13,261 |
|
|
|
14,047 |
|
|
|
12,896 |
|
|
|
24,099 |
|
|
|
23,240 |
|
|
|
25,300 |
|
|
Net capitalized costs |
|
$ |
972 |
|
|
$ |
819 |
|
|
$ |
548 |
|
|
$ |
6,583 |
|
|
$ |
6,539 |
|
|
$ |
6,006 |
|
|
|
|
Other |
|
|
Total |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties |
|
$ |
56 |
|
|
$ |
63 |
|
|
$ |
58 |
|
|
$ |
41,241 |
|
|
$ |
40,228 |
|
|
$ |
39,610 |
|
|
Unproved oil and gas properties |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,730 |
|
|
|
4,480 |
|
|
|
5,198 |
|
|
Total capital cost |
|
|
56 |
|
|
|
63 |
|
|
|
58 |
|
|
|
44,971 |
|
|
|
44,708 |
|
|
|
44,808 |
|
|
Accumulated DD&A |
|
|
56 |
|
|
|
63 |
|
|
|
58 |
|
|
|
37,416 |
|
|
|
37,350 |
|
|
|
38,254 |
|
|
Net capitalized costs |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
7,555 |
|
|
$ |
7,358 |
|
|
$ |
6,554 |
|
134
Costs incurred includes both capitalized costs and costs charged to expense when incurred. Costs incurred also includes internal costs directly related to acquisition, exploration, and development activities, new asset retirement costs established in the current year as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.
|
|
|
Canada |
|
|
United States |
|
||||||||||||||||||
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
$ |
17 |
|
|
$ |
31 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
21 |
|
|
$ |
4 |
|
|
Proved |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
|
|
205 |
|
|
Total acquisition costs |
|
|
17 |
|
|
|
31 |
|
|
|
1 |
|
|
|
- |
|
|
|
23 |
|
|
|
209 |
|
|
Exploration costs |
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
4 |
|
|
|
13 |
|
|
Development costs |
|
|
631 |
|
|
|
425 |
|
|
|
255 |
|
|
|
1,330 |
|
|
|
1,354 |
|
|
|
860 |
|
|
Total costs incurred |
|
$ |
649 |
|
|
$ |
457 |
|
|
$ |
257 |
|
|
$ |
1,332 |
|
|
$ |
1,381 |
|
|
$ |
1,082 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|||||||||
|
|
|
|
|
|
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
|
|
|
|
|
|
$ |
17 |
|
|
$ |
52 |
|
|
$ |
4 |
|
|
Proved |
|
|
|
|
|
|
|
|
- |
|
|
|
2 |
|
|
|
206 |
|
|
Total acquisition costs |
|
|
|
|
|
|
|
|
17 |
|
|
|
54 |
|
|
|
210 |
|
|
Exploration costs |
|
|
|
|
|
|
|
|
3 |
|
|
|
5 |
|
|
|
14 |
|
|
Development costs |
|
|
|
|
|
|
|
|
1,961 |
|
|
|
1,779 |
|
|
|
1,115 |
|
|
Total costs incurred |
|
|
|
|
|
|
|
$ |
1,981 |
|
|
$ |
1,838 |
|
|
$ |
1,339 |
|
COSTS NOT SUBJECT TO DEPLETION OR AMORTIZATION
Upstream costs in respect of significant unproved properties are excluded from the country cost centre’s depletable base as follows:
|
As at December 31 |
|
|
|
2018 |
|
|
2017 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
$ |
237 |
|
|
$ |
311 |
|
|
United States |
|
|
|
|
3,493 |
|
|
|
4,169 |
|
|
|
|
|
|
$ |
3,730 |
|
|
$ |
4,480 |
|
The following is a summary of the costs related to Encana’s unproved properties as at December 31, 2018:
|
|
|
2018 |
|
|
2017 |
|
|
2016 |
|
|
Prior to 2016 |
|
|
Total |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition Costs |
|
$ |
223 |
|
|
$ |
238 |
|
|
$ |
88 |
|
|
$ |
3,033 |
|
|
$ |
3,582 |
|
|
Exploration Costs |
|
|
18 |
|
|
|
2 |
|
|
|
5 |
|
|
|
123 |
|
|
|
148 |
|
|
|
|
$ |
241 |
|
|
$ |
240 |
|
|
$ |
93 |
|
|
$ |
3,156 |
|
|
$ |
3,730 |
|
Acquisition costs primarily include costs incurred to acquire or lease properties. Exploration costs primarily include costs related to geological and geophysical studies and costs of drilling and equipping exploratory wells. Ultimate recoverability of these costs and the timing of inclusion within the applicable country cost centre’s depletable base is dependent upon either the finding of proved oil, NGL and natural gas reserves, expiration of leases or recognition of impairments.
135
Included in the $3.7 billion of oil and gas properties not subject to depletion or amortization are approximately $3.5 billion of acquired leasehold and mineral costs in the Permian related to the Company’s acquisition of Athlon Energy Inc. in 2014. These acquisition costs are associated with acquired acreage for which proved reserves have yet to be assigned from future development. The Company continually assesses the development timeline of the acquired acreage. The timing and amount of the transfer of property acquisition costs into the depletable base are based on several factors and may be subject to changes over time from drilling plans, drilling results, availability of capital, project economics and other assessments of the property. The inclusion of these acquisition costs in the depletable base is expected to occur within 7 to 11 years. The remaining costs excluded from depletion are related to properties which are not individually significant.
|
28. |
Supplemental Quarterly Financial Information (unaudited) |
The following summarizes quarterly financial data for the fiscal years of 2018 and 2017:
|
|
|
2018 |
|
|||||||||||||
|
(US$ millions, except per share amounts) |
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
2,381 |
|
|
$ |
1,262 |
|
|
$ |
983 |
|
|
$ |
1,313 |
|
|
Impairments |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Operating Income (Loss) |
|
|
1,354 |
|
|
|
119 |
|
|
|
(116 |
) |
|
|
337 |
|
|
Gain (Loss) on Divestitures, net |
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Before Income Tax |
|
$ |
1,179 |
|
|
$ |
45 |
|
|
$ |
(221 |
) |
|
$ |
160 |
|
|
Income Tax Expense (Recovery) |
|
|
149 |
|
|
|
6 |
|
|
|
(70 |
) |
|
|
9 |
|
|
Net Earnings (Loss) |
|
$ |
1,030 |
|
|
$ |
39 |
|
|
$ |
(151 |
) |
|
$ |
151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share - Basic & Diluted |
|
$ |
1.08 |
|
|
$ |
0.04 |
|
|
$ |
(0.16 |
) |
|
$ |
0.16 |
|
|
|
|
2017 |
|
|||||||||||||
|
(US$ millions, except per share amounts) |
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,210 |
|
|
$ |
861 |
|
|
$ |
1,083 |
|
|
$ |
1,289 |
|
|
Impairments |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Operating Income (Loss) |
|
|
262 |
|
|
|
(4 |
) |
|
|
321 |
|
|
|
489 |
|
|
Gain (Loss) on Divestitures, net |
|
|
(1 |
) |
|
|
406 |
|
|
|
- |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Before Income Tax |
|
$ |
147 |
|
|
$ |
522 |
|
|
$ |
327 |
|
|
$ |
434 |
|
|
Income Tax Expense (Recovery) |
|
|
376 |
|
|
|
228 |
|
|
|
(4 |
) |
|
|
3 |
|
|
Net Earnings (Loss) |
|
$ |
(229 |
) |
|
$ |
294 |
|
|
$ |
331 |
|
|
$ |
431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share - Basic & Diluted |
|
$ |
(0.24 |
) |
|
$ |
0.30 |
|
|
$ |
0.34 |
|
|
$ |
0.44 |
|
136
Item 9 : Changes in and Disagreements with Acco untants on Accounting and Financial Disclosure
The financial statements for the fiscal years ended December 31, 2018, 2017, and 2016, included in this Annual Report on Form 10-K, have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.
Item 9A: Controls and Procedures
EVALUATION AND DISCLOSURE CONTROLS AND PROCEDURES
Encana’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2018.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
See “Management’s Assessment of Internal Control Over Financial Reporting” under Item 8 of this Annual Report on Form 10-K.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
See “Report of Independent Registered Public Accounting Firm” under Item 8 of this Annual Report on Form 10-K.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in Encana’s internal control over financial reporting during the fourth quarter of 2018 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. See “Management’s Assessment of Internal Control Over Financial Reporting” under Item 8 of this Annual Report on Form 10-K.
None.
137
Item 10 . Directors, Executive Officers and Corporate Governance
DIRECTORS AND EXECUTIVE OFFICERS
Information regarding the Board of Directors is set forth in the Proxy Statement relating to the Company’s 2019 annual meeting of shareholders, which is incorporated herein by reference.
Information regarding the Company’s executive officers is set forth in the section entitled “Executive Officers of the Registrant” under Items 1 and 2 of this Annual Report on Form 10-K.
CODE OF ETHICS
Encana has adopted a code of ethics entitled the “Business Code of Conduct” (the “Code of Ethics”), that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. The Code of Ethics is available for viewing on Encana’s website at www.encana.com , and is available in print to any shareholder who requests it. Requests for copies of the Code of Ethics should be made by contacting Encana’s Corporate Secretary by mail at 4400, 500 Centre Street S.E., P.O. Box 2850, Calgary, Alberta, T2P 2S5, Canada or by telephone at (403) 645-2000. Encana intends to disclose and summarize any amendment to, or waiver from, any provision of the Code of Ethics that is required to be so disclosed and summarized, on its website at www.encana.com .
Item 11. Executive Compensation
The information required by this Item 11 is set forth in the Proxy Statement relating to the Company’s 2019 annual meeting of shareholders, which is incorporated herein by reference.
The executive compensation and related information incorporated by reference herein shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The information required by this Item 12 is set forth in the Proxy Statement relating to the Company’s 2019 annual meeting of shareholders, which is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this Item 13 is set forth in the Proxy Statement relating to the Company’s 2019 annual meeting of shareholders, which is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required by this Item 14 is set forth in the Proxy Statement relating to the Company’s 2019 annual meeting of shareholders, which is incorporated herein by reference.
138
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as part of this Annual Report on Form 10-K or incorporated by reference:
1. Consolidated Financial Statements
Reference is made to the Consolidated Financial Statements and notes thereto appearing in Item 8 of this Annual Report on Form 10-K.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the Consolidated Financial Statements or notes thereto.
3. Exhibits
Exhibits are listed in the exhibit index below. The exhibits include management contracts, compensatory plans and arrangements required to be filed as exhibits to the Annual Report on Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
|
Exhibit No |
Description |
|
2.1 |
|
|
3.1 |
|
|
3.2 |
|
|
3.3 |
|
|
4.1 |
|
|
4.2 |
|
|
4.3 |
|
|
4.4 |
|
|
4.5 |
|
|
4.6 |
|
|
4.7 |
|
|
4.8 |
|
|
4.9 |
|
|
4.10 |
|
|
4.11 |
|
|
4.12 |
|
|
4.13 |
139
|
4.15 |
|
|
4.16 |
|
|
4.17 |
|
|
4.18 |
|
|
4.19 |
|
|
4.20 |
|
|
4.21 |
|
|
4.22 |
|
|
4.23 |
|
|
4.24 |
|
|
4.25 |
|
|
4.26 |
|
|
4.27 |
|
|
10.1 |
|
|
10.2 |
|
|
10.3 |
|
|
10.4 |
140
|
10.6* |
|
|
10.7* |
|
|
10.8* |
|
|
10.9* |
|
|
10.10* |
|
|
10.11* |
|
|
10.12* |
|
|
10.13* |
|
|
10.14* |
|
|
10.15* |
|
|
10.16* |
|
|
10.17* |
|
|
10.18* |
|
|
10.19* |
|
|
10.20* |
|
|
10.21* |
|
|
10.22* |
141
|
10.24* |
|
|
10.25* |
|
|
10.26* |
|
|
10.27* |
|
|
10.28* |
|
|
10.29* |
|
|
10.30* |
|
|
10.31* |
|
|
10.32* |
|
|
10.33* |
|
|
10.34* |
|
|
10.35* |
|
|
10.36* |
|
|
10.37* |
|
|
10.38* |
|
|
10.39* |
|
|
10.40 |
|
|
10.41 |
|
|
10.42* |
142
|
10.44* |
Omnibus Incentive Plan of Encana Corporation adopted with effect from February 13, 2019. |
|
10.45* |
|
|
10.46* |
|
|
10.47* |
|
|
10.48* |
|
|
10.49* |
|
|
14.1 |
|
|
21.1 |
|
|
23.1 |
|
|
23.2 |
|
|
23.3 |
|
|
24.1 |
Power of Attorney (included on the signature page of this report). |
|
31.1 |
|
|
31.2 |
|
|
32.1 |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350. |
|
32.2 |
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350. |
|
99.1 |
|
|
99.2 |
|
|
101.INS |
XBRL Instance Document. |
|
101.SCH |
XBRL Taxonomy Schema Document. |
|
101.CAL |
XBRL Calculation Linkbase Document. |
|
101.LAB |
XBRL Label Linkbase Document. |
|
101.DEF |
XBRL Definition Linkbase Document. |
|
101.PRE |
XBRL Presentation Linkbase Document. |
* Management contract or compensatory arrangement.
None.
143
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
|
|
|
|
|
|
|
|
ENCANA CORPORATION
|
|
|
|
|
By: |
/s/ Sherri A. Brillon |
|
|
|
|
Name: Sherri A. Brillon |
|
|
|
|
Title: Executive Vice-President & Chief Financial Officer |
Dated: February 28, 2019
144
SIGNATURES WITH RESPECT TO ENCANA CORPORATION
Each person whose signature appears below hereby constitutes and appoints Douglas J. Suttles and Sherri A. Brillon, and each of them, any of whom may act without the joinder of the other, the true and lawful attorney-in-fact and agent of the undersigned, with full power of substitution and resubstitution, for and in the name, place and stead of the undersigned, in any and all capacities, to sign any and all amendments, including any post-effective amendments, and supplements to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Commission, and hereby grants to such attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
This Power of Attorney may be executed in multiple counterparts, each of which shall be deemed an original, but which taken together shall constitute one instrument.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Annual Report on Form 10-K has been signed by the following persons in the capacities and on the dates indicated.
|
Signature |
Capacity |
Date |
|
/s/ Clayton H. Woitas
|
Chairman of the Board
|
February 28, 2019 |
|
/s/ Douglas J. Suttles
|
President & Chief Executive Officer and Director (Principal Executive Officer) |
February 28, 2019 |
|
/s/ Sherri A. Brillon
|
Executive Vice-President
|
February 28, 2019 |
|
/s/ Peter A. Dea
|
Corporate Director |
February 28, 2019 |
|
/s/ Fred J. Fowler
|
Corporate Director |
February 28, 2019 |
|
/s/ Howard J. Mayson
|
Corporate Director |
February 28, 2019 |
|
/s/ Lee A. McIntire
|
Corporate Director |
February 28, 2019 |
|
/s/ Margaret A. McKenzie Margaret A. McKenzie |
Corporate Director |
February 28, 2019 |
|
/s/ Steven W. Nance
|
Corporate Director |
February 28, 2019 |
|
/s/ Suzanne P. Nimocks
|
Corporate Director |
February 28, 2019 |
|
/s/ Thomas G. Ricks Thomas G. Ricks
|
Corporate Director |
February 28, 2019 |
|
/s/ Brian G. Shaw Brian G. Shaw |
Corporate Director |
February 28, 2019 |
|
/s/ Bruce G. Waterman Bruce G. Waterman |
Corporate Director |
February 28, 2019 |
145
Exhibit 23.1
Exhibit 23.3
Exhibit 99.2
