10-K 1 d191939d10k.htm 10-K 10-K
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

 

[X]

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

or

 

[   ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-15226

 

 

LOGO

ENCANA CORPORATION

(Exact name of registrant as specified in its charter)

 

Canada    Not Applicable
(State or other jurisdiction of incorporation or organization)    (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:

 

Title of each

class

  

Name of each exchange

on which registered

Common Shares    New York Stock Exchange

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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes [X] No [    ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer [X] Accelerated filer [    ] Non-accelerated filer [    ] Smaller reporting company [    ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

Yes [    ] No [X]

 

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2016    $       6,621,347,962      

Number of registrant’s common shares outstanding as of February 17, 2017

     973,064,884      

Documents Incorporated by Reference

Portions of registrant’s definitive proxy statement (“Proxy Statement”) for the registrant’s 2017 annual meeting of shareholders to be held May 2, 2017 (to be filed with the Securities and Exchange Commission prior to April 30, 2017) are incorporated by reference in Part III of this Annual Report on Form 10-K.


Table of Contents

ENCANA CORPORATION

FORM 10-K

TABLE OF CONTENTS

 

PART I   

Items 1 and 2. Business and Properties

     6  

Item 1A.

 

Risk Factors

     27  

Item 1B.

 

Unresolved Staff Comments

     36  

Item 3.

 

Legal Proceedings

     36  

Item 4.

 

Mine Safety Disclosures

     36  
PART II   

Item 5.

  Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities      37  

Item 6.

 

Selected Financial Data

     40  

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     42  

Item 7A. 

 

Quantitative and Qualitative Disclosures about Market Risk

     73  

Item 8.

 

Financial Statements and Supplementary Data

     75  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     132  

Item 9A.

 

Controls and Procedures

     132  

Item 9B.

 

Other Information

     132  
PART III   

Item 10.

 

Directors, Executive Officers and Corporate Governance

     133  

Item 11.

 

Executive Compensation

     133  

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters      133  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

     133  

Item 14.

 

Principal Accountant Fees and Services

     133  
PART IV   

Item 15.

 

Exhibits and Financial Statement Schedules

     134  

Signatures

     137  

 

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DEFINITIONS

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.

“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.”, “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. 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; statements with respect to the Company’s strategic objectives including capital allocation strategy, focus of investment, growth of high margin liquids volumes, operating efficiencies, ability to reduce costs and ability to preserve balance sheet strength; the continued evolution of the Company to drive greater productivity and cost efficiencies while reducing its environmental footprint; efficiencies resulting from the Company’s multi-basin portfolio; balancing commodity portfolio; anticipated commodity prices; ability to accelerate activity levels; ability to optimize well and completion designs, including changes to lateral lengths drilled, stage and well spacing; 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 construction of compression and processing capacity; 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 and leverage ratios; anticipated cash and cash equivalents; anticipated hedging and outcomes of risk management program; managing risk, including the impact of changes in laws and

 

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regulations; level of expenditures and impact of environmental legislation; adequacy of provisions for abandonment and site reclamation costs; financial flexibility and discipline; access to cash and cash equivalents and other methods of funding; the 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 a downgrade to its credit rating; access to the Company’s credit facilities; planned annualized dividend and the declaration and payment of future dividends, if any; the adequacy of the Company’s provision for taxes and legal claims; the projections and expectation of meeting the targets contained in the Company’s corporate guidance; 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; flexibility and source of funding of capital spending plans; anticipated staffing levels; expected future interest expense; the Company’s commitments and obligations; potential future discounts, if any, in connection with the Company’s dividend reinvestment program; 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; the Company’s ability to access its revolving credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance 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; the 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; enforceability of transaction agreements; 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, the benefits achieved and general industry expectations.

Risks and uncertainties that may affect these business outcomes include: the ability to generate sufficient cash flow to meet the Company’s obligations; risks inherent to completing transactions on a timely basis or at all and adjustments that may impact the expected value to Encana; commodity price volatility; ability to secure adequate product 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; the timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk; risk and effect of a downgrade in credit rating, including below an investment-grade credit rating, and its impact on access to capital markets and other sources of liquidity; fluctuations in currency and interest rates; risks inherent in the Company’s corporate guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential future lawsuits and regulatory actions made against the Company; impact to the Company as a result of disputes arising with its partners, including the suspension by its partners of certain of their obligations and the 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 of natural gas and liquids from plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; 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.

 

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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 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.

 

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PART I

Items 1 and 2. Business and Properties

GENERAL

Encana is a leading North American energy producer that is focused on developing its multi-basin portfolio of natural gas, oil and NGL producing plays. Encana’s operations also include the marketing of natural gas, oil and NGLs. All of Encana’s reserves and production are 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. Effective January 1, 2017, Encana was required to comply with the reporting requirements applicable to U.S. domestic issuers. Previously, under the multijurisdictional disclosure system adopted by Canada and the United States, reports and other information (including financial information) were prepared, in part, in accordance with the disclosure requirements of Canada, which differ from those in the United States. The public may read any document Encana files with or furnishes to the SEC at the SEC’s public reference room at Room 1580, 100 F Street, N.E., Washington, D.C. 20549. Readers may also obtain copies of the same documents from the public reference room of the SEC at 100 F Street, N.E., Washington D.C. 20549 by paying a fee. Please call the SEC at 1-800-SEC-0330 or contact them at www.sec.gov for further information on the public reference room. Encana’s filings are also electronically available 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.

 

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STRATEGY

The Company is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. The Company’s key objectives include:

 

   

Exercising a disciplined capital allocation strategy that focuses investment on a limited number of core assets

   

Growing high margin liquids volumes

   

Maximizing profitability through operational efficiencies and reducing costs

   

Preserving balance sheet strength

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 the oil and gas resources within the plays. Encana continually strives to improve operating efficiencies, foster technological innovation and lower its cost structures while reducing its environmental footprint through play optimization. Capital and operating efficiencies are achieved across Encana’s multi-basin portfolio through the rapid deployment of successful operating practices that are repeated across the Company’s operations, optimizing equipment and processes and by applying continuous improvement techniques.

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.

During 2016, the oil and natural gas industry continued to experience low commodity prices driven by supply and demand imbalances. In spite of this trend, Encana has continued to execute on its strategy focusing on lowering operational and capital cost structures, enhancing operating efficiencies, and reducing debt to maintain appropriate liquidity and financial flexibility. Encana also emphasized financial discipline by further focusing capital investment to a limited number of core assets with high growth and return potential, reducing activity levels in non-strategic assets and bringing costs into alignment with the current commodity price environment. The Company believes that continued execution of its strategy will ensure Encana is well positioned for the current price environment and ready to accelerate activity levels if commodity prices improve in the future. 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 natural gas and oil reserves. The Company is also focused on creating and capturing additional value through its market optimization segment. The Company conducts substantially all of its business through subsidiaries. Encana’s operating and reportable segments are: (i) Canadian Operations; (ii) USA Operations; and (iii) Market Optimization.

 

   

Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within Canada. Core assets that are part of Encana’s strategic focus to accelerate growth 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 include: Wheatland in southern Alberta, Horn River in northeast British Columbia and Deep Panuke located offshore Nova Scotia.

 

   

USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S. Core assets that are part of Encana’s strategic focus to accelerate growth 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 and primarily include: San Juan in northwest New Mexico, Piceance in northwest Colorado and Tuscaloosa Marine Shale in east Louisiana and west Mississippi.

 

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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.

OIL AND GAS PROPERTIES AND ACTIVITIES

The following map outlines the location of Encana’s North American landholdings and assets as at December 31, 2016.

 

 

LOGO

 

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The term ‘Core Asset’ in the map above reflects plays identified with high growth and return potential and are the focus of the Company’s current capital investment and development plan. The term ‘Other’ in the map above reflects base and option value plays. Base plays are allocated funds to target efficiency programs that include enhancing operational efficiency and cost reductions rather than development programs. Option value plays are emerging plays that may receive funding for development based on strategic fit, play profitability driven by price and energy fundamentals and portfolio diversity.

Canadian Operations

Overview: In 2016, the Canadian Operations had total capital investment of approximately $256 million and drilled approximately 44 net wells all of which were in Montney and Duvernay. Production averaged approximately 966 MMcf/d of natural gas, approximately 2.0 Mbbls/d of oil, and approximately 25.2 Mbbls/d of NGLs. At December 31, 2016, the Canadian Operations had an established land position in Canada of approximately 2.4 million net acres including approximately 1.2 million net undeveloped acres. In addition, the Canadian Operations accounted for 39% of production sales during 2016 and 50% of total proved reserves as at December 31, 2016.

During 2016, Encana divested of approximately 54,200 net acres related to the Gordondale assets in Montney located in northwestern Alberta for proceeds of approximately $455 million, after closing adjustments.

The following tables summarize the Canadian Operations landholdings, producing wells and daily production as at and for the periods indicated.

 

Landholdings   Developed
Acreage
    Undeveloped
Acreage
    Total
Acreage
    

Average 

Working 

Interest 

 
(thousands of acres at December 31, 2016)         Gross          Net             Gross          Net             Gross          Net       

Montney

    595          377         772          513         1,367          890          65%   

Duvernay

    106          44         530          325         636          369          58%   

Other Upstream Operations (1)

    826          700         605          393         1,431          1,093          76%   

Total Canadian Operations

    1,527          1,121         1,907          1,231         3,434          2,352          68%   

(1) Other Upstream Operations includes Wheatland, Horn River and Deep Panuke.

Producing Wells

     Natural Gas     Oil           Total  
(number of wells at December 31, 2016) (1)          Gross          Net             Gross          Net                     Gross          Net   

Montney

     1,197          1,082         6          5           1,203          1,087   

Duvernay

     134          67         9          2           143          69   

Other Upstream Operations (2)

     5,241          5,096         24          16                 5,265          5,112   

Total Canadian Operations

     6,572          6,245         39          23                 6,611          6,268   
(1)

Figures exclude wells capable of producing, but not producing.

(2)

Other Upstream Operations includes Wheatland, Horn River and Deep Panuke.

 

                NGLs  
Production   Natural Gas
(MMcf/d)
    Oil
(Mbbls/d)
    Plant Condensate
(Mbbls/d)
    Other
(Mbbls/d)
         

Total

(Mbbls/d)

 
(average daily)         2016          2015             2016          2015             2016          2015             2016          2015                     2016            2015  

Montney (1)

    735          723         1.9          4.7         10.4          9.4         6.2          8.4           16.6          17.8  

Duvernay

    54          27         -          0.3         7.1          4.3         1.2          0.2           8.3          4.5  

Other Upstream Operations (2)

    177          221         0.1          0.6         0.1          0.2         0.2          0.3                 0.3          0.5  

Total Canadian Operations

    966          971         2.0          5.6         17.6          13.9         7.6          8.9                 25.2          22.8  
(1)

During 2016, Encana divested of the Gordondale assets in Montney. Production from Gordondale in 2016, prior to the disposition, averaged 45 MMcf/d of natural gas, 1.6 Mbbls/d of oil and 3.7 Mbbls/d of NGLs (2015 - averaged 96 MMcf/d of natural gas and 4.1 Mbbls/d of oil and 6.1 Mbbls/d of NGLs).

 
(2)

Other Upstream Operations includes Wheatland, Horn River and Deep Panuke.

 

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Montney

Montney is primarily a condensate rich natural gas play located in northeast British Columbia and northwest Alberta. Although the Montney landholdings include additional producing horizons, that being the Cadomin, Doig and Granite Wash formations, the current focus of development is on the Montney formation within the play. In 2016, total production from the play averaged approximately 735 MMcf/d of natural gas and approximately 18.5 Mbbls/d of oil and NGLs. As at December 31, 2016, Encana controlled approximately 890,000 net acres in the play.

Encana is currently targeting the development of natural gas and condensate rich locations in the Montney formation within the play, of which Encana controlled approximately 483,000 net acres, including 282,000 net undeveloped acres at December 31, 2016. The Montney formation has up to six stacked horizons spanning over 1,000 feet of stratigraphy and is being developed exclusively with horizontal well technology. In 2016, Encana continued to focus on drilling higher liquids content wells, drilling approximately 24 net horizontal wells and production averaged approximately 639 MMcf/d of natural gas and approximately 18.5 Mbbls/d of oil and NGLs in the Montney formation. Significant improvements have been achieved with respect to horizontal well completions with the application of multi-stage hydraulic fracturing. During 2016, Encana has continued to optimize completion designs and apply advanced technologies, reducing total development costs by approximately 26 percent, on a completed interval basis. During 2016, Encana also drilled wells with lateral lengths ranging from approximately 6,600 to 11,700 feet and tighter inter-well spacing ranging from approximately 650 to 1,000 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change.

Encana has a partnership agreement with a subsidiary of Mitsubishi Corporation (“Mitsubishi”), the Cutbank Ridge Partnership (“CRP”), to jointly develop certain lands predominately in Montney. Under the agreement, Mitsubishi agreed to invest approximately C$2.9 billion for its 40 percent partnership interest in the CRP, of which approximately C$2.2 billion has been received as of December 31, 2016. In addition to its 40 percent of the CRP’s future capital funding investment, Mitsubishi is expected to invest the remaining amount of approximately C$0.7 billion under an agreed upon five-year development plan of the area, thereby reducing Encana’s capital funding commitment to 30 percent of the total expected capital investment over that development plan.

As at December 31, 2016, Encana has access to natural gas processing capacity of approximately 820 MMcf/d, of which approximately 600 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 895 MMcf/d, of which approximately 780 MMcf/d is under contract with third parties under varying terms and duration and approximately 110 MMcf/d is owned by the Company. In addition, Encana expects to have access to additional compression and processing facilities with capacity of approximately 480 MMcf/d and liquids handling of 49.1 Mbbls/d that are currently under construction and are expected to be completed in late 2017 to 2018.

Duvernay

Duvernay is an emerging liquids rich shale gas play located in west central Alberta and includes properties that are primarily located in the Duvernay formation, but also holds potential in other formations such as the Montney. As at December 31, 2016, Encana controlled approximately 369,000 net acres in the play.

The Duvernay formation within the play primarily comprises approximately 335,000 net acres, including 295,000 net undeveloped acres, and extends across the Simonette, Pinto, Edson and Willesden Green properties. Encana is currently targeting the development of condensate rich locations in the north and south Simonette areas of the formation using horizontal well technology and pad drilling. Encana is currently achieving significant improvements in drilling costs and cycle times through innovation and continuing to develop long-term take-away capacity. In 2016, Encana drilled approximately 20 net wells in the area and production averaged approximately 54 MMcf/d of natural gas and approximately 8.3 Mbbls/d of oil and NGLs. During 2016, Encana

 

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drilled wells with lateral lengths ranging from approximately 5,200 to 10,200 feet with tighter inter-well spacing ranging from approximately 490 to 1,300 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change.

Encana has an agreement with a subsidiary of PetroChina Company Limited (“PetroChina”) to jointly explore and develop certain Duvernay lands. Under the agreement, PetroChina agreed to invest approximately C$2.18 billion for a 49.9 percent working interest in the lands. PetroChina has invested approximately C$2.08 billion as of December 31, 2016 and is expected to further invest approximately C$96.6 million over the remaining commitment period that expires in 2020, which will be used to fund half of Encana’s capital commitment.

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 78 MMcf/d with NGLs production capacity of 19.2 Mbbls/d. During 2016, natural gas processing capacity increased by 25 MMcf/d with the addition of a new plant in Simonette to support the Duvernay growth profile.

Other Upstream Operations:

Wheatland

Wheatland is located in southern Alberta and includes producing horizons such as the Lethbridge and Horseshoe Canyon formations, shallow sands formations including the Belly River, Medicine Hat and deeper natural gas formations including the Glauconitic and Mannville formations. Production averaged approximately 76 MMcf/d of natural gas and approximately 0.4 Mbbls/d of oil and NGLs. As at December 31, 2016, Encana had approximately 5,164 gross producing wells (5,059 net producing wells) and controlled approximately 757,000 net acres in the play, which includes 109,000 net undeveloped acres. Historically, Encana has used an integrated wellbore strategy with development focused on natural gas along the eastern edge of the Horseshoe Canyon Fairway. In 2016, Encana focused on play optimization, reducing production declines and lowering operating costs. At December 31, 2016, Encana controlled approximately 484,000 net acres in the Horseshoe Canyon Fairway.

Horn River

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 2016, Encana’s natural gas production averaged approximately 58 MMcf/d. As at December 31, 2016, Encana had approximately 97 gross producing horizontal wells (49 net producing horizontal wells) and controlled approximately 168,000 net acres, which includes 147,000 net undeveloped acres in the Horn River Basin shales. Encana owns interest in natural gas compression capacity in Horn River of approximately 285 MMcf/d at various facilities in the area. Encana has a processing arrangement with a third party related to a previously planned expansion of the Cabin natural gas processing plant, for which commissioning and expansion was suspended in 2012.

Deep Panuke

Encana is the owner and operator of the Deep Panuke gas field located offshore Nova Scotia, which is approximately 250 kilometres southeast of Halifax on the Scotian shelf. Natural gas from Deep Panuke is produced and processed by an offshore Production Field Centre (“PFC”). The PFC is under a lease arrangement which has an initial term that expires in 2021, with the option to extend the lease for 12 successive one-year terms at fixed prices after the initial lease term. Produced gas is transported to Goldboro, Nova Scotia, via subsea pipeline which interconnects with the Maritimes & Northeast Pipeline, where the natural gas is ultimately transported to markets in eastern Canada and northeastern U.S.

In 2016, natural gas production averaged approximately 52 MMcf/d. Encana sells all natural gas produced from Deep Panuke under a long-term physical sales contract at the prevailing market prices in that region. At December 31, 2016, Encana had approximately 4 gross producing wells (4 net producing wells) and controlled approximately 30,000 net acres offshore Nova Scotia. Encana operates five of its six licenses in these areas.

 

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USA Operations

Overview:  In 2016, the USA Operations had total capital investment of approximately $873 million and drilled approximately 116 net wells all of which were in Eagle Ford and Permian. Production averaged approximately 417 MMcf/d of natural gas, approximately 71.7 Mbbls/d of oil, and approximately 23.2 Mbbls/d of NGLs. At December 31, 2016, the USA Operations had an established land position of approximately 1.2 million net acres including approximately 0.8 million net undeveloped acres. In addition, the USA Operations accounted for 61% of production sales during 2016 and 50% of total proved reserves as at December 31, 2016.

During 2016, Encana divested of approximately 51,000 net acres in DJ Basin located in northern Colorado for proceeds of approximately $633 million, after closing adjustments.

The following tables summarize the USA Operations landholdings, producing wells and daily production as at and for the periods indicated.

 

Landholdings   Developed
Acreage
    Undeveloped
Acreage
    Total
Acreage
   

Average 

Working 

Interest 

 
(thousands of acres at December 31, 2016)           Gross                Net               Gross          Net               Gross          Net      

Eagle Ford

    42          41         1          1         43          42         98%   

Permian

    97          91         39          36         136          127         93%   

Other Upstream Operations (1)

    412          334         964          739         1,376          1,073         78%   

Total USA Operations

    551          466         1,004          776         1,555          1,242         80%   
(1)

Other Upstream Operations includes San Juan, Piceance and Tuscaloosa Marine Shale.

Producing Wells

 

    Natural Gas     Oil     Total  
(number of wells at December 31, 2016) (1)           Gross          Net               Gross          Net               Gross          Net     

Eagle Ford

    49          45         392          383         441          428     

Permian

    -          -         1,530          1,434         1,530          1,434     

Other Upstream Operations (2)

    4,265          3,452         167          99         4,432          3,551     

Total USA Operations

    4,314          3,497         2,089          1,916         6,403          5,413     
(1)

Figures exclude wells capable of producing, but not producing.

(2)

Other Upstream Operations includes San Juan, Piceance and Tuscaloosa Marine Shale.

 

                NGLs  
Production   Natural Gas
(MMcf/d)
    Oil
(Mbbls/d)
    Plant Condensate
(Mbbls/d)
    Other
(Mbbls/d)
    Total
(Mbbls/d)
 
(average daily)           2016        2015             2016        2015               2016            2015             2016        2015             2016          2015  

Eagle Ford

    48         44        32.4         37.0        0.6         0.5        6.6         5.3        7.2          5.8  

Permian

    50         44        29.8         24.5        1.1         0.9        8.9         7.4        10.0          8.3  

Other Upstream Operations (1, 2, 3)

    319         576        9.5         19.9        1.0         1.5        5.0         8.0        6.0          9.5  

Total USA Operations

    417         664        71.7         81.4        2.7         2.9        20.5         20.7        23.2          23.6  
(1)

Other Upstream Operations includes San Juan, Piceance and Tuscaloosa Marine Shale.

(2)

During 2016, Encana divested of DJ Basin. Other Upstream Operations includes production from DJ Basin prior to the disposition in 2016, which averaged 32 MMcf/d of natural gas, 3.4 Mbbls/d of oil and 3.0 Mbbls/d of NGLs (2015 – averaged 55 MMcf/d of natural gas and 9.4 Mbbls/d of oil and 5.5 Mbbls/d of NGLs).

(3)

During 2015, Encana divested of Haynesville. Other Upstream Operations includes production from Haynesville prior to the disposition in 2015, which averaged 173 MMcf/d of natural gas.

Eagle Ford

Eagle Ford is a tight oil play located in south Texas in the Karnes, Wilson 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, 2016, Encana controlled approximately 42,000 net acres in the play. In 2016, Encana drilled approximately 28 net wells in the area and production averaged approximately 32.4 Mbbls/d of oil, approximately 48 MMcf/d of natural gas and approximately 7.2 Mbbls/d of NGLs.

 

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While Encana is focused on developing the lower Eagle Ford exclusively using horizontal drilling, in 2016, Encana also began optimizing upper Eagle Ford targets. In 2016, Encana drilled lateral lengths ranging from approximately 2,000 to 8,800 feet with an average measured total depth of approximately 16,500 feet and optimized other development parameters such as completions designs. The new completions designs utilize thin fluid combined with tighter cluster spacing of less than 25 feet, to create a complex fracture system to increase well productivity. Since acquiring the play in 2014, Encana has reduced drilling costs by approximately 40 percent as a result of the Company’s focus on well design optimization activities. As Encana continues to optimize well and completion designs, lateral lengths drilled, cluster spacing and well spacing may change. During 2016, Encana began delineating the Austin Chalk, drilling two wells in September with lateral lengths averaging approximately 3,400 feet and a third well in late December, with a lateral length of approximately 4,200 feet.

Oil and natural gas production is gathered at various production facilities. The majority of the oil is subsequently transported to sales points by pipeline or trucked from facilities depending on the sales contract. Encana also has access to firm natural gas gathering capacity of up to approximately 35 MMcf/d and processing capacity of up to approximately 70 MMcf/d with third parties under varying terms and duration. Encana also has access to interruptible capacity for the excess production and during 2016, Encana utilized total firm and interruptible capacity of approximately 100 MMcf/d.

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, 2016, Encana controlled approximately 127,000 net acres in the play. The properties are characterized by an extensive production history from vertical drilling and development and mature infrastructure, with multiple producing horizons spanning approximately 4,000 feet of stratigraphy (also referred to as “stacked pay zones”). In 2016, Encana drilled 78 horizontal net wells and 10 vertical net wells in the area. In 2016, production averaged approximately 29.8 Mbbls/d of oil, approximately 50 MMcf/d of natural gas and approximately 10.0 Mbbls/d of NGLs.

With exposure to 11 potential productive horizons, Encana has focused development using multi-well horizontal pad drilling in order to maximize resource recovery and minimize the development footprint. During 2016, Encana focused on optimizing completion design by using 3D stratigraphic models to land the well bore in the desired drilling zone, minimizing interference between wells and maximizing drainage through well spacing and better fluid and sand utilization. In addition, Encana continued drilling longer horizontal wells with lateral lengths ranging from approximately 5,000 to 10,000 feet at a measured average total depth of approximately 17,300 feet in 2016. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change. During 2016, Encana’s multi-well horizontal drilling strategy has reduced drilling costs by approximately 15 percent.

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 signed in 2015, which has an initial term of seven years, with an option to extend the term an additional seven years. In the event of pipeline capacity constraints, Encana’s oil production is trucked by a third party. Natural gas is gathered by Encana and transported to the purchaser’s meter and pipeline interconnection point.

Other Upstream Operations:

San Juan

San Juan is a light sweet oil play located in the San Juan Basin in northwest New Mexico where Encana has a significant land position. Development historically focused on the liquids in Tocito and El Valdo formations

 

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within the play. In 2016, production averaged approximately 3.9 Mbbls/d of oil and NGLs and approximately 9 MMcf/d of natural gas. At December 31, 2016, Encana had approximately 204 gross producing wells (109 net producing wells) and controlled approximately 203,000 net acres in the play, which includes 164,000 net undeveloped acres. In 2016, Encana focused on play optimization reducing production declines and lowering operating costs. Encana has access to natural gas processing capacity of up to approximately 50 MMcf/d under a dedication agreement with a third party.

Piceance

Piceance is a play located in northwest Colorado where Encana historically focused development on natural gas in the Williams Fork, Iles, Mancos and Niobrara formations within the play. Wells targeting the Williams Fork and Iles formations produce from tight gas sands while the Mancos and Niobrara produce from marine shales. In 2016, production averaged approximately 271 MMcf/d of natural gas, approximately 2.8 Mbbls/d of oil and NGLs. At December 31, 2016, Encana had approximately 3,967 gross producing natural gas wells (3,236 net producing natural gas wells) and controlled approximately 693,000 net acres in the play, which includes 447,000 net undeveloped acres.

In 2016, Encana and a subsidiary of Nucor Corporation (“Nucor”) terminated the long-term joint venture agreement related to development of natural gas in the North Piceance Basin. In conjunction with the terminated joint development agreement, Nucor acquired a working interest in certain acreage located in the South Piceance Basin from Encana, and in exchange Encana acquired remaining interests in natural gas gathering and water handling assets located in the North Piceance Basin from an affiliated entity that was jointly owned by Encana and Nucor.

Encana has access to natural gas processing capacity of approximately 715 MMcf/d, of which approximately 650 MMcf/d is under contract with third parties under varying terms and duration and approximately 65 MMcf/d is owned by the Company. Encana also has access to high pressure natural gas gathering capacity of approximately 850 MMcf/d and low pressure natural gas gathering and compression of approximately 500 MMcf/d with third parties under varying terms and duration. Encana owns approximately 500 MMcf/d of low pressure natural gas gathering and compression capacity, of which approximately 420 MMcf/d is primarily tying into a high pressure third party gathering system. Encana also has access to NGLs transportation of approximately 30.0 Mbbls/d with a third party for production from San Juan and Piceance with a remaining term of eight years.

Tuscaloosa Marine Shale

The Tuscaloosa Marine Shale is an emerging oil play located in east Louisiana and west Mississippi. As an emerging play, the potential for future development is primarily dependent on play profitability driven by price and energy fundamentals. Encana has established a significant land position in the core of the play and is focused on maximizing oil recovery in the Tuscaloosa Marine Shale formation. In 2016, Encana focused on play optimization reducing production declines and lowering operating costs. Production averaged approximately 2.4 Mbbls/d of oil. At December 31, 2016, Encana had approximately 48 gross producing oil wells (32 net producing oil wells) and controlled approximately 144,000 net acres, which includes 117,000 net undeveloped acres.

PROVED RESERVES AND OTHER OIL AND GAS INFORMATION

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment. Encana’s estimates of proved reserves and associated future net cash flows were evaluated by the Company’s engineers and are the responsibility of management. As a result, Encana has developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and regulations. Encana’s policies assign responsibilities for compliance in reserves bookings and require that reserve estimates be made by qualified reserves evaluators (“QREs”). QRE is defined as a registered professional licensed to practice engineering, geology, geophysics and has a minimum of five years practical experience, with at least three recent years of experience in the evaluation of reserves.

 

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Encana’s Vice-President, Corporate Reserves and 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 and 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 internal policies that prescribe procedures and standards to be followed for preparing, estimating and recording reserves in compliance with applicable SEC definitions and guidance. All QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group.

The Company’s Director, Corporate Reserves reports to Encana’s Vice-President, Corporate Reserves and 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 and is a member of the Calgary Chapter of the Society of Petroleum Evaluation Engineers. In addition, the Corporate Reserves Group comprises a total of seven engineers, four of whom have professional designations, with a combined relevant experience of over 130 years.

Encana’s Reserves Committee of the Board of Directors 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 the independent qualified reserves auditors (“IQRAs”) retained by the Company. Annually, the Reserves Committee recommends the selection of IQRAs to the Board of Directors for its approval and meets with the IQRAs to review their reports.

Encana’s QREs prepare the Company’s reserves estimates. Annually, each play is reviewed in detail by the QREs, the Company’s Corporate Reserves Group, the Company’s executive officers and an internal Reserves Review Committee, as appropriate. In addition, the Corporate Reserves Group 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 executive leadership and the Reserves Committee of the Board of Directors, for approval by the Board of Directors.

In 2016, Encana retained IQRAs to audit the Company’s reserves estimates. McDaniel & Associates Consultants Ltd. audited 98 percent of Encana’s estimated Canadian proved reserves volumes and Netherland, Sewell & Associates, Inc. audited 100 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 flow 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. For the 2015 and 2014 periods presented, Encana retained independent qualified reserves evaluators to evaluate and prepare reports on 100 percent of Encana’s natural gas, oil and NGLs reserves volumes.

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 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

 

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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 effects of regulation by governmental agencies, and operating costs, all of which may vary materially from actual results. 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.

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 this report. 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 in 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, 2016 and was prepared as of January 16, 2017. The audit reports prepared by the IQRA’s are attached in Exhibits 99.1 and 99.2 of this Annual Report on Form 10-K.

 

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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.

Proved Reserves

The table below summarizes the Company’s total proved reserves by natural gas, oil and NGLs and by geographic area as at December 31, 2016 and other summary operating data.

 

    As at December 31, 2016  
      Canada        U.S.        Total     

Proved Reserves:(1)

     

Natural Gas (Bcf):

     

Developed

    903        951        1,853     

Undeveloped

    907        142        1,049     

Total

    1,810        1,093        2,902     

Oil (MMbbls):

     

Developed

    -        82.5        82.5     

Undeveloped

    -        73.1        73.1     

Total

    -        155.6        155.6     

Natural Gas Liquids (MMbbls):

     

Developed

    25.6        31.8        57.4     

Undeveloped

    68.4        24.6        93.0     

Total

    94.0        56.4        150.4     

Total Proved Reserves (MMBOE):

     

Developed

    176.1        272.7        448.8     

Undeveloped

    219.6        121.4        341.0     

Total

    395.6        394.1        789.7     

Percent Proved Developed

    44 %        69 %        57 %     

Percent Proved Undeveloped

    56 %        31 %        43 %     

Production (MBOE/d)

    188.2        164.5        352.7     

Capital Investments (millions)

  $                     256      $                     873      $                     1,129     

Total Net Producing Wells (2)

    6,692        5,484        12,176     

Standardized Measure of Discounted Net Cash Flows: (3)

     

Pre-Tax (millions)

  $ 441      $ 1,247      $ 1,688     

Taxes (millions)

    -        -        -     

After-Tax (millions)

  $ 441      $ 1,247      $ 1,688     
(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.

 

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Changes to the Company’s proved reserves during 2016 are summarized in the table below:

 

     2016  
      

 

Natural Gas

(Bcf)

  

  

    

 

Oil

(MMbbls)

  

  

    

 

NGLs

(MMbbls)

  

  

    

 

Total 

(MMBOE) 

  

  

Beginning of year

     3,064          164.3          124.5          799.4     

Revisions and improved recovery

     (244)         (15.9)         (8.0)         (64.7)    

Extensions and discoveries

     887          52.2          75.8          275.7     

Purchase of reserves in place

     16          9.6          2.6          14.9     

Sale of reserves in place

     (313)         (27.6)         (26.8)         (106.5)    

Production

     (506)         (27.0)         (17.7)         (129.1)    

End of year

     2,902          155.6          150.4          789.7     

Developed

     1,853          82.5          57.4          448.8     

Undeveloped

     1,049          73.1          93.0          341.0     

Total

     2,902          155.6          150.4          789.7     

* Numbers may not add due to rounding.

In 2016, Encana’s proved natural gas reserves of approximately 2,902 Bcf decreased 162 Bcf from 2015 primarily due to sales of reserves in place of 313 Bcf resulting from the Company’s strategy to focus development on a limited number of core assets. Revisions and improved recovery of natural gas included a reduction of 462 Bcf due to lower 12-month average trailing natural gas prices, partially offset by technical revisions other than price of 218 Bcf. Extensions and discoveries of 887 Bcf were due to successful drilling and delineation of the Montney, Duvernay, Permian and Eagle Ford assets.

In 2016, Encana’s proved oil and NGLs reserves of 306.0 MMbbls increased 17.2 MMbbls from 2015 primarily due to extensions and discoveries of 128.0 MMbbls, offset by sale of reserves of 54.4 MMbbls and negative revisions and improved recovery of 23.9 MMbbls. 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.

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, 2016 were WTI: $42.75 per Bbl for oil, Edmonton Light Sweet: C$52.21 per Bbl for oil, Henry Hub: $2.49 per MMBtu for natural gas, and AECO: C$2.17 per MMBtu for natural gas. Prices for natural gas, oil and NGLs can fluctuate widely.

Proved Undeveloped Reserves

Changes to the Company’s proved undeveloped reserves during 2016 are summarized in the table below:

 

(MMBOE)      2016     

Beginning of year

     262.8     

Revisions of prior estimates

     (80.8)    

Extensions and discoveries

     218.6     

Conversions to developed

     (29.7)    

Purchase of reserves in place

     11.3     

Sale of reserves in place

     (41.2)    

End of Year

     341.0     

* Numbers may not add due to rounding.

As of December 31, 2016, there were no material proved undeveloped reserves that had remained undeveloped for five years or more after disclosure as proved undeveloped reserves.

Revisions of prior estimates were revised down by 80.8 MMBOE primarily due to lower 12-month average trailing prices. Extensions and discoveries of 218.6 MMBOE were achieved through the extension of proved acreage, primarily as a result of successful drilling in Montney, Duvernay and Permian.

 

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Conversions of proved undeveloped reserves to proved developed status were 29.7 MMBOE, equating to 11 percent of the total prior year-end proved undeveloped reserves. Approximately 52 percent of proved undeveloped reserves conversions occurred in Canada primarily in Montney and Duvernay and 48 percent occurred in the U.S. primarily in Permian and Eagle Ford. Encana spent $173 million to develop proved undeveloped reserves in 2016, of which approximately 31 percent related to the Canadian properties and 69 percent related to the U.S. properties.

Sales of reserves in place of 41.2 MMBOE relate to the Company’s divestitures of the DJ Basin and Gordondale assets in Montney. Purchases of proved undeveloped reserves of 11.3 MMBOE relate to acquisitions in the Eagle Ford and Permian.

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:

 

    Production     Average Sales Price(1)          

Average  

Production  

Cost(2)  

 
    

Natural Gas

(Bcf)

   

Oil

(MMbbls)

   

NGLs  

(MMbbls)  

   

Natural Gas

($/Mcf)

   

Oil

($bbls)

   

NGLs  

($bbls)  

           ($/BOE)    

2016

               

Canada

    353        0.7        9.2          1.77        36.32        32.32            10.69     

USA

    153        26.3        8.5          2.29        38.67        14.86                  10.89     

Total

    506        27.0        17.7          1.93        38.61        23.94                  10.78     

2015

               

Canada

    354        2.0        8.3          2.75        43.90        29.21            11.74     

USA

    242        29.8        8.6          2.60        43.31        14.37                  13.96     

Total

    596        31.8        16.9          2.69        43.35        21.66                  12.92     

2014

               

Canada

    503        5.0        8.6          4.89        82.86        53.41            11.42     

USA

    355        13.0        5.0          4.62        81.27        38.92                  12.76     

Total

    858        18.0        13.6          4.78        81.71        48.09                  12.01     
(1)

Excludes the impact of commodity derivatives.

(2)

Excludes ad valorem, severance and property taxes.

The following table summarizes the Company’s revenues by product sold and by geographic area for each of the last three years:

 

($ millions)    Net Production Sales     

Other    

Revenue(1)

     Gains (losses) on
risk management, net
    

Total

Revenue

 
  

Natural

Gas

     Oil      NGLs           

2016

                                                     

Canada

       $       628       $           26       $           298         $           166       $           (151)       $           967    

USA

     350         1,015         126           584         (124)         1,951    

Total

       $ 978       $ 1,041       $ 424         $ 750       $ (275)       $ 2,918    

2015

                 

Canada

       $ 976       $ 90       $ 243         $ 222       $ 166        $ 1,697    

USA

     629         1,288         124           258         426          2,725    

Total

       $ 1,605       $ 1,378       $ 367         $ 480       $ 592        $ 4,422    

2014

                 

Canada

       $ 2,468       $ 412       $ 460         $ 552       $ 167        $ 4,059    

USA

     1,640         1,063         195           857         205          3,960    

Total

       $ 4,108       $ 1,475       $ 655         $ 1,409       $ 372        $ 8,019    
(1)

Includes market optimization and other revenues such as purchased product sold to third parties, sublease revenues, interest income and gathering and processing services provided to third parties.

 

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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.

 

     Exploration     Development     Total  
       Productive        Dry       Productive        Dry       Productive        Dry  
       Gross        Net          Gross        Net           Gross        Net          Gross        Net           Gross        Net         Gross        Net     

  2016

                                 

  Canada

     1        -        1        -         100        44        3        -         101        44        4        -    

  USA

     3        3        -        -         124        113        -        -         127        116        -        -    

  Total

     4        3        1        -         224        157        3        -         228        160        4        -    

  2015

                                 

  Canada

     -        -        1        -         173        135        -        -         173        135        1        -    

  USA

     -        -        -        -         402        265        2        -         402        265        2        -    

  Total

     -        -        1        -         575        400        2        -         575        400        3        -    

  2014

                                 

  Canada

     5        2        -        -         358        277        -        -         363        279        -        -    

  USA

     6        2        -        -         394        202        1        -         401        204        1        -    

  Total

     11        4        -        -         752        479        1        -         764        483        1        -    
  (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.

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, 2016.

 

     Wells in the Process of Drilling or
in Active Completion
    Wells Suspended or Waiting on
Completion (3) 
 
     Exploration     Development     Exploration     Development  
         Gross        Net          Gross        Net           Gross        Net          Gross        Net      

  2016

                    

  Canada

     -        -         20        12         -        -         21        13      

  USA

     -        -         27        27         -        -         8        8      

  Total

     -        -         47        39         -        -         29        21      
(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)

Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

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, 2016.

 

  Producing Wells (1, 2)    Natural Gas (3)     Oil (4)     Total  
       Gross        Net          Gross        Net          Gross        Net       

  2016

               

  Canada

     7,097        6,635         92        57         7,189        6,692      

  USA

     4,374        3,549         2,108        1,935         6,482        5,484      

  Total

     11,471        10,184         2,200        1,992         13,671        12,176      
  (1)

“Gross” wells are the total number of wells in which Encana has an interest.

 

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  (2)

“Net” wells are the number of wells obtained by aggregating Encana’s working interest in each of its gross wells.

  (3)

Includes 10,273 gross natural gas wells (9,782 net natural gas wells) containing multiple completions.

  (4)

Includes 69 gross oil wells (14 net oil wells) containing multiple completions.

The following table summarizes Encana’s developed, undeveloped and total landholdings by geographic area as at December 31, 2016.

 

Landholdings (1 - 6)         Developed      Undeveloped      Total  
(thousands of acres)           Gross          Net            Gross          Net            Gross          Net        

Canada

                    

Onshore

   — Crown      938         581           1,622         1,019           2,560         1,600      
   — Freehold      568         519           226         197           794         716      
   — Fee      1         1           3         3           4         4      

Offshore

   — Crown      20         20           56         12           76         32      

Total Canada

          1,527         1,121           1,907         1,231           3,434         2,352      

United States

                    
   — Federal/State      289         242           697         523           986         765      
   — Freehold      252         214           271         217           523         431      
     — Fee      10         10           36         36           46         46      

Total United States

          551         466           1,004         776           1,555         1,242      

International

                    

Australia

          -         -           104         40           104         40      

Total International

          -         -           104         40           104         40      

Total

          2,078         1,587           3,015         2,047           5,093         3,634      
(1)

Fee lands are those lands in which Encana has a fee simple interest in the mineral rights and has either: (i) not leased out all of the mineral zones; (ii) retained a working interest; or (iii) one or more substances or products that have not been leased. The current fee lands acreage summary includes all fee titles owned by Encana that have one or more zones that remain unleased or available for development.

(2)

Crown/Federal/State lands are those owned by the federal, provincial or state government or the First Nations, in which Encana has purchased a working interest lease.

(3)

Freehold lands are owned by individuals (other than a government or Encana), in which Encana holds a working interest lease.

(4)

Gross acres are the total area of properties in which Encana has an interest.

(5)

Net acres are the sum of Encana’s fractional interest in gross acres.

(6)

Undeveloped acreage refers to those acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

Of the total 3.6 million net acres, approximately 1.6 million net acres is held by production. The table above includes the acreage subject to leases that will expire over the next three years: 2017 – approximately 196,000 net acres; 2018 – approximately 100,000 net acres; and 2019 – approximately 230,000 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

 

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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.

MARKETING ACTIVITIES

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 five years.

Encana’s produced natural gas, oil and NGLs 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.

The majority of Encana’s natural gas production is sold under short-term delivery contracts less than 12 months in duration, at the relevant monthly or daily market price at the time the product is sold. Encana has dedicated natural gas produced from Deep Panuke under a long-term physical sales contract at prevailing market prices in that region. Encana’s oil production is sold under short term and long term contracts that range up to four years. 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 12 years, or under dedication arrangements at the relevant market price at the time the product is sold.

Encana also seeks to mitigate the market risk associated with future cash flows by entering into various financial risk management contracts relating to produced natural gas, oil and NGLs. Details of contracts related to Encana’s various financial risk management positions are found in Note 24 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 natural gas, oil and NGLs, some of which require the delivery of fixed and determinable quantities. As of December 31, 2016, Encana was committed to deliver 64,000 MMcf of natural gas and 179 Mbbls of oil and NGLs in the Canadian Operations and 29,000 MMcf of natural gas in the USA Operations with terms under one year. The Company had no commitments to deliver fixed quantities of production with terms exceeding one year.

Certain delivery commitments result in the following financial commitments associated with transportation and processing:

 

($ millions)      1 Year        2-3 Years        4-5 Years        > 5 years        Total    

Transportation & Processing

              

Canadian Operations

              

Natural Gas

     270        548        456        1,781        3,055    

Oil & NGLs

     22        100        110        246        478    

Total Canadian Operations

     292        648        566        2,027        3,533    

USA Operations

              

Natural Gas

     185        448        453        484        1,570    

Oil & NGLs

     31        47        37        55        170    

Total USA Operations

     216        495        490        539        1,740    

Total Canadian and USA Operations

     508        1,143        1,056        2,566        5,273    

 

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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.

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 natural gas and liquids for the year ended December 31, 2016, the Company had two customers, Royal Dutch Shell Group and Flint Hills Resources, which individually accounted for more than 10 percent of Encana’s consolidated revenues (2015–two customers, Royal Dutch Shell Group and Flint Hills Resources, 2014one customer, BP Energy Company). 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 natural gas, oil and NGLs reserves;

   

Reserves and property acquisitions;

   

Transportation and marketing of natural gas, oil, NGLs 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 natural gas, oil or NGLs.

EMPLOYEES

At December 31, 2016, Encana employed 2,200 employees as set forth in the following table.

 

       Employees      

Canada

     1,129          

U.S.

     1,071          

Total

     2,200          

The Company also engages a number of contractors and service providers.

 

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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 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 produce 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 us 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.

 

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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 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

     56        4      President & Chief Executive Officer

  Joanne L. Alexander

     50        2      Executive Vice-President, General Counsel & Corporate Secretary

  Sherri A. Brillon

     57        10      Executive Vice-President & Chief Financial Officer

  David G. Hill

     55        3      Executive Vice-President, Exploration & Business Development

  Michael G. McAllister

     58        6      Executive Vice-President & Chief Operating Officer

  Michael Williams

     57        3      Executive Vice-President, Corporate Services

  Renee E. Zemljak

     52        7      Executive Vice-President, Midstream, Marketing & Fundamentals
  (1)

  As of February 27, 2017

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 Ceres, Inc. (a public energy crop company) and NEOS GeoSolutions (a privately held geosciences 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 & Corporate Secretary in 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

 

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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.

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 (both are oil and gas companies).

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 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).

 

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ITEM 1A.

Risk Factors

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 and by prices of alternate sources of energy (including refined product, coal, and renewable energy initiatives). 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, reliance on industry partners and service providers, unexpected cost increases, royalties, taxes, volatility in natural gas, oil or NGLs prices, the availability of drilling and other equipment, the ability to access lands, the ability to access water for hydraulic fracturing operations, weather, the availability and proximity of processing and pipeline

 

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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.

Declines in natural gas, oil or NGLs prices 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,

 

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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.

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 natural gas, oil and NGLs 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.

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

 

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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 U.S. Environmental Protection Agency (“EPA”) has outlined a series of steps to address methane and volatile organic compound emissions from the oil and gas industry, including a new goal to reduce oil and gas methane emissions by 40 percent to 45 percent from 2012 levels by 2025. The reductions will be achieved through regulatory and voluntary measures currently under development. In addition, the Canadian federal government along with certain provinces and territories, including Alberta and British Columbia, have announced a pan-Canadian climate change framework that is consistent with the outcome reached at the 21st 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 of C$20 per tonne in January 2017, increasing to C$30 in 2018, while British Columbia has an established carbon levy of C$30 per tonne. 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.

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.

 

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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 of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the United States and has been correlated with hydraulic fracturing in Western Canada 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.

The Company’s level of indebtedness may limit its financial flexibility.

As at December 31, 2016, 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.

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.

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 was downgraded 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

 

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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 the downgrade to one of the Company’s credit ratings, 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.

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 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.

Encana may not realize anticipated benefits or be subject to unknown risks from acquisitions.

Encana has completed a number of acquisitions in order 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.

Acquiring oil and natural gas properties requires the Company to assess reservoir and infrastructure characteristics, including estimated recoverable reserves, type curve performance and future production, commodity prices, revenues, development and operating costs and potential environmental and other liabilities.

 

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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 or in new or emerging formations. New or emerging formations and areas often have limited or no production history and the Company may be less able to predict future drilling and production results over the life-cycles of the wells in such areas. Further, the Company also 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.

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, 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.

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. 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.

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 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.

Encana’s operations are subject to the risk of business interruption and casualty losses. The Company’s insurance may not fully protect us against these risks and liabilities.

The Company’s business is subject to all of 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

 

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well control, surface spills and uncontrolled ground releases of fluids during hydraulic fracturing or other similar activities, 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, spills and migration of hazardous chemicals, pollution and other environmental risks.

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. Unauthorized access to these 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. The Company applies technical and process controls in line with industry-accepted standards to protect its information assets and systems and are reviewed by the appropriate senior management with oversight from the Company’s Board of Directors; 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, and the Company may be required to expend significant additional resources to investigate, mitigate and remediate any potential vulnerabilities.

We maintain insurance against some, but not all, of these risks and losses. The occurrence of a significant event against the Company which Encana is not fully insured could have a material adverse effect on the Company’s financial position.

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 be 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.

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 operations of these assets or their associated costs. Encana’s dependence

 

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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 a number of 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.

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 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

 

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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.

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, royalty regimes, environmental laws or other laws and regulations may in the future be changed or 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.

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 assurance that the Company will be able to continue to attract and retain such personnel with the required specialized skills necessary for its business.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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 26 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.

 

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PART II

Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

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”. The following table sets forth the price range of Encana’s common shares as reported by the TSX and NYSE for the periods indicated:

 

    

Toronto Stock

Exchange

          

New York Stock

Exchange

 
         High            Low                  High            Low    
       (C$ per share)                        ($ per share)          

2016

             

Three months ended:

             

December 31, 2016

     17.70          12.03            13.40          8.96    

September 30, 2016

     13.87          9.56            10.75          7.35    

June 30, 2016

     11.47          7.41            9.03          5.63    

March 31, 2016

     8.26          4.14            6.37          3.01    

2015

             

Three months ended:

             

December 31, 2015

     11.97          6.49            9.23          4.66    

September 30, 2015

     13.94          7.44            11.09          5.55    

June 30, 2015

     17.75          13.50            14.72          10.82    

March 31, 2015

     17.79          13.50                  14.36          10.54    

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 17, 2017, there were approximately 973 million common shares outstanding held by 25,268 shareholders of record, and no Class A Preferred Shares outstanding.

Dividend Information

In 2016, Encana paid a quarterly dividend of US$0.015 per share (US$0.06 per share annually). In 2015, Encana paid a quarterly dividend of US$0.07 per share (US$0.28 per share annually). 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.

 

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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 2017 annual meeting of shareholders, which is incorporated herein by reference.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

None.

RECENT SALES OF UNREGISTERED EQUITY SECURITIES

None.

 

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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 24 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 Anadarko Petroleum Corporation; Apache Corporation; Baytex Energy Corporation; Cabot Oil & Gas Corporation; Canadian Natural Resources Limited; Chesapeake Energy Corporation; Concho Resources Inc.; Continental Resources Inc.; Crescent Point Energy Corporation; Enerplus Corporation; Devon Energy Corporation; EOG Resources Inc.; Hess Corporation; Murphy Oil Corporation; Newfield Exploration Corporation; Noble Energy Inc.; Marathon Oil Corporation; Penn West Petroleum Ltd.; Pengrowth Energy Corporation; Pioneer Natural Resources Company; Range Resources Corporation; Southwestern Energy Company; Vermillion Energy Inc.; and Whiting Petroleum Corporation. The graph was prepared assuming $100 was invested on December 31, 2011 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.

Comparison of 5-Year Cumulative Total Return Among

Encana Corporation, the S&P 500, the S&P/TSX Composite Index, and a Peer Group

 

 

LOGO

 

Fiscal Year Ended December 31    2011      2012      2013      2014      2015      2016    

Encana

   $     100.00      $     111.00      $     105.00      $ 82.00      $ 32.00      $ 74.00    

Peer Group

     100.00        94.00        123.00        97.00        59.00        86.00    

S&P 500

     100.00        116.00        153.00            174.00        176.00        197.00    

S&P/TSX Composite Index

     100.00        107.00        121.00        134.00            123.00            148.00    

 

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Item 6: Selected Financial Data

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2016, which has been derived from the Company’s audited 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, except as indicated)    2016           2015           2014           2013           2012     

Statement of Earnings Data:

                      

Revenues

     2,918              4,422              8,019              5,858              5,160      

Impairments

     1,396              6,473              -              21              4,695      

Operating Income (Loss)

     (1,881)             (6,301)             2,331              870              (4,415)     

Gain (Loss) on Divestitures, Net

     390              14              3,426              7              -      

Net Earnings (Loss) Attributable to Common Shareholders

     (944)             (5,165)             3,392              236              (2,794)     

Per Share Data:

                      

Net Earnings (Loss) per Common Share Basic & Diluted

     (1.07)             (6.28)             4.58              0.32              (3.79)     

Dividends Declared per Common Share

     0.06              0.28              0.28              0.67              0.80      

Weighted Average Common Shares Outstanding
Basic & Diluted (millions)

     882.6              822.1              741.0              737.7              736.3      

Balance Sheet Data:

                      

Cash and Cash Equivalents

     834              271              338              2,566              3,179      

Total Assets (1)(2)

     14,653              15,614              24,492              17,599              18,599      

Capital Lease Obligations and The Bow Office Building

     1,570              1,591              1,959              2,175              1,743      

Long-Term Debt, Including Current Portion (2)

     4,198              5,333              7,301              7,078              7,623      

Total Shareholders’ Equity

     6,126              6,167              9,685              5,147              5,295      

Statement of Cash Flow Data:

                      

Cash From (Used In) Operating Activities

     625              1,681              2,667              2,289              3,107      

Non-GAAP Cash Flow (3)

     838              1,430              2,934              2,581              3,537      

Capital Expenditures

     1,132              2,232              2,526              2,712              3,476      

Net Acquisitions & (Divestitures)

     (1,052)             (1,838)             (1,329)             (521)             (3,664)     

Foreign Exchange Rates (US$ per C$1):

                      

Average

     0.755              0.782              0.905              0.971              1.000      

Period End

     0.745              0.723              0.862              0.940              1.005      

Production Volumes:

                      

Natural Gas (MMcf/d)

     1,383              1,635              2,350              2,777              2,981      

Oil (Mbbls/d)

     73.7              87.0              49.4              25.8              17.6      

Total NGLs (Mbbls/d) (4)

     48.4              46.4              37.4              28.1              13.4      

Total Oil & NGLs (Mbbls/d)

     122.1              133.4              86.8              53.9              31.0      

Total Production (MBOE/d)

     352.7              405.9              478.5              516.7              527.9      

Commodity Prices, Including Realized Gain (Loss) on
Risk Management:

                      

Natural Gas ($/Mcf)

     2.10              3.89              4.59              4.09              4.82      

Oil ($/bbl)

     48.68              49.68              86.03              88.19              84.06      

Total NGLs ($/bbl) (4)

     23.90              21.66              48.09              48.95              63.37      

Oil & NGLs ($/bbl)

     38.85              39.93              69.70              67.75              75.12      

Total ($/BOE)

     21.69              28.81              35.21              29.05              31.62      

 

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(1)

As a result of early adopting ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, the Company reclassified current deferred income taxes to non-current deferred income taxes of: 2014 - $90 million; 2013 - $3 million; and 2012 - $49 million.

(2) 

As a result of adopting ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs”, the Company reclassified debt issuance costs resulting in a decrease to Other Assets with a corresponding decrease to Long-Term Debt of: 2015 - $30 million; 2014 - $39 million; 2013 - $46 million; and 2012 - $52 million.

(3)

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.

(4)

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.

 

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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, 2016 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:

 

   

Executive Overview

   

Results of Operations

   

Liquidity and Capital Resources

   

Accounting Policies and Estimates

   

Non-GAAP Measures

 

 

 Executive Overview

 

Strategy

 

 

Encana is a leading North American energy producer that is focused on developing its multi-basin portfolio of natural gas, oil and NGL producing plays. Encana is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. The Company is pursuing the key business objectives of exercising a disciplined capital allocation strategy by investing in a limited number of core assets, growing high margin liquids volumes, maximizing profitability through operating efficiencies and reducing costs, and preserving balance sheet strength.

To excel in executing its strategy, Encana focuses on the 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.

As a result of Encana’s continual review and evaluation of its strategy and changing market conditions, during 2016 Encana focused on quality growth from high margin, scalable projects located in some of the best plays in North America referred to as the “Core Assets”, comprising Montney and Duvernay in Canada and Eagle Ford and Permian in the U.S. These world-class assets form a multi-basin portfolio enabling flexible and efficient investment of capital. The Company rapidly deploys successful ideas and practices across these assets, becoming more efficient as innovative and sustainable technical improvements are implemented.

For additional information on Encana’s strategy, its reporting segments and the plays in which the Company operates, refer to Items 1 and 2 of this Annual Report on Form 10-K. In evaluating its operations, the Company reviews performance-based measures such as Non-GAAP Cash Flow and Corporate Margin 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.

2016 Highlights

 

Encana has been committed to building a business model that allows the Company to adapt to fluctuating commodity prices. Despite the market environment in 2016, Encana achieved strong results through its focus on cost reduction and capital efficiency. Lower benchmark prices during 2016 compared to 2015 contributed to decreases in Encana’s average realized natural gas and liquids prices of 28 percent and 8 percent, respectively, resulting in lower revenues, additional ceiling test impairments and a reduction in Encana’s capital program. Encana took steps to strengthen its balance sheet and improve its liquidity through divestitures, a public share offering and debt repayments.

 

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Significant Developments

 

   

Raised gross proceeds of $1.15 billion through a public offering of 123,050,000 common shares of Encana. A portion of the proceeds was used to repay indebtedness under the Company’s credit facilities.

 

   

Streamlined the Company’s portfolio of properties and raised funds through the sale of the Company’s DJ Basin assets located in northern Colorado and the Company’s Gordondale assets in Montney located in northwestern Alberta, generating proceeds of approximately $1.1 billion, after closing and other adjustments, which were used to repay indebtedness under the Company’s credit facilities.

 

   

Strengthened the balance sheet through the completion of tender offers for the purchase of $489 million of senior notes.

 

   

Completed a restructuring to align staffing levels and the organizational structure with the Company’s reduced capital spending program as a result of the low commodity price environment. Including the impact of the sale of the DJ Basin assets, Encana reduced its workforce by approximately 20 percent in 2016.

Financial Results

 

   

Reported a net loss of $944 million, including before-tax amounts for non-cash ceiling test impairments of $1,396 million, a gain on divestitures of $390 million, net losses on risk management of $261 million, a foreign exchange gain of $210 million and long-term incentive costs of $134 million, as well as a deferred tax valuation allowance of $121 million.

 

   

Generated cash from operating activities of $625 million and Non-GAAP Cash Flow of $838 million.

 

   

Paid dividends of $0.06 per share.

 

   

Held cash and cash equivalents of $834 million and had available credit facilities of $4.5 billion for total liquidity of $5.3 billion at year end.

 

   

Reduced long-term debt by $1.1 billion from 2015 and lowered interest expense on debt, excluding a one-time payment, by 11 percent.

Capital Investment

 

   

Drilled productive and low cost wells, leading to highly efficient capital activity focused on the Core Assets where 97 percent of total capital spending was directed.

 

   

Focused on short-cycle high margin projects which has allowed the Company to respond to fluctuations in commodity prices and reduce capital spending without compromising the strategy.

Production

 

   

Average natural gas production volumes of 1,383 MMcf/d and average oil and NGL production volumes of 122.1 Mbbls/d which accounted for 65 percent and 35 percent of total production volumes, respectively.

 

   

Core Assets production was 72 percent of total production volumes.

Operating Expenses

 

   

Realized significant cost savings through operational improvements. Reduced transportation and processing expense by $351 million, or 28 percent, and reduced operating expense, excluding long-term incentive costs, by $180 million, or 25 percent, compared to 2015.

 

   

Completed an organizational restructuring and realized efficiencies which reduced administrative expense by $34 million, or 15 percent, excluding the impact of long-term incentive costs and restructuring charges.

 

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2017 Outlook

 

Industry Outlook

The oil and gas industry is cyclical and commodity prices are volatile. Oil prices during 2017 are expected to reflect global supply and demand dynamics as well as the geopolitical environment. A recent agreement among members of OPEC and select non-OPEC countries to temporarily cut crude oil production starting in January 2017 has been supportive of oil prices; however, the agreement could be offset by increased North American production or non-compliance with the agreement. Natural gas prices are expected to improve in 2017 as expectations for a colder winter relative to 2016, coupled with increases in exports and industrial demand, may absorb the oversupply that depressed prices to multi-year lows in 2015 and 2016. After declining in 2016, natural gas production in the contiguous U.S. is not expected to increase significantly until additional pipeline infrastructure in the U.S. northeast is able to alleviate bottlenecks in that region.

Company Outlook

Encana believes proactive measures taken in 2016 and previous years have positioned the Company to be flexible and to continue to achieve strong returns from the Core Assets through this evolving commodity price cycle.

Encana enters into commodity derivative financial instruments on a portion of its expected natural gas, oil and condensate production volumes to reduce volatility and help sustain revenues during periods of lower prices. As of January 31, 2017, Encana’s 2017 commodity price mitigation program covers 70 to 75 percent of expected total production.

Capital Investment

Total anticipated 2017 capital investment of approximately $1.6 billion to $1.8 billion is expected to be funded from 2017 cash generated from operating activities and cash on hand. Encana plans to focus the majority of its capital investment on its Core Assets with an objective to grow value in these plays. The majority of the 2017 capital program is expected to be allocated to growing Encana’s Permian production through increasing the number of rigs in the play, which is anticipated to result in approximately twice as many new Permian horizontal wells on stream in 2017 as compared to 2016. Capital investment in Montney is expected to be allocated to both Cutbank Ridge and Pipestone. Cutbank Ridge production is expected to ramp up in the latter half of 2017 to flow through two new facilities that are expected to be completed in late 2017.

To further enhance the economics of its Core Assets, Encana expects to continually improve well performance and lower drilling and completion costs through efficiency gains and lower service costs. The impact of Encana’s disciplined capital program and continuous innovation will allow the Company to increase its inventory of premium return well locations in the Core Assets, creating flexibility and opportunity to grow cash flows and production volumes going forward.

Production

In 2017, Encana expects natural gas production volumes of 1,150 MMcf/d to 1,200 MMcf/d and liquids production volumes of 125.0 Mbbls/d to 130.0 Mbbls/d. Core Asset production is expected to increase by more than 20 percent from the fourth quarter of 2016 to the fourth quarter of 2017. Encana also expects to increase liquids production to over 40 percent of total production in the fourth quarter of 2017 and anticipates 2017 Core Asset production will account for the majority of total production volumes. Growing production in the Core Assets is expected to increase cash flows and deliver competitive returns.

 

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Operating Expenses

Encana expects to maintain its focus on reducing upstream operating expenses, transportation and processing costs, and administrative costs through efficiency improvements and lower service costs. Encana expects to see ongoing benefits from cost savings initiatives implemented and contract renegotiations completed in 2016 with expected operating expense of $3.75 per BOE to $4.25 per BOE and transportation and processing expense of $6.50 per BOE to $7.00 per BOE. The Company anticipates that the current staffing levels can efficiently support accelerated activity levels in 2017 with expected administrative expense of $1.40 per BOE to $1.60 per BOE. Operating expense and administrative expense exclude long-term incentive costs. Lower interest expense is expected as a result of steps taken in 2016 to decrease debt levels. Inflation has been insignificant in recent years, but is still a factor in the North American economy and Encana may experience inflationary pressure on the cost of services.

Further information on Encana’s 2017 Corporate Guidance can be accessed on the Company’s website at www.encana.com.

 

 

 Results of Operations

 

The following discussion of Encana’s results of operations for each of the years in the three-year period ended December 31, 2016, should be read in conjunction with the Consolidated Financial Statements and notes thereto included in Item 8 of this Annual Report on Form 10-K.

Selected Financial Information

 

 

($ millions)    2016        2015        2014    

 

Product Revenues

   $ 2,443        $ 3,350        $ 6,238    

 

Gains (Losses) on Risk Management, net

     (275)         592          372    

 

Market Optimization

     647          368          1,251    

 

Other

     103          112          158    

Total Revenues

     2,918          4,422          8,019    

 

Total Operating Expenses (1)

     4,799          10,723          5,688    

 

Operating Income (Loss)

     (1,881)         (6,301)         2,331    

 

Total Other (Income) Expenses

     (261)         1,709              (2,298)   

 

Net Earnings (Loss) Before Income Tax

         (1,620)         (8,010)         4,629    

 

Net Earnings (Loss)

   $ (944)       $     (5,165)       $ 3,426    
(1)

Total Operating Expenses include non-cash items such as DD&A, impairments, accretion of asset retirement obligations and long-term incentive costs.

 

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Revenues

 

Encana’s revenues are substantially derived from sales of natural gas, oil and NGL production. Increases or decreases in Encana’s revenue, profitability and future production are highly dependent on the commodity prices the Company receives. Prices are market driven and the Company expects that future prices will continue to fluctuate due to factors beyond its control, such as supply and demand, seasonality and geopolitical and economic factors. Canadian Operations realized prices are closely linked to the AECO and Edmonton Light Sweet benchmark prices, except for production from Deep Panuke which is closely related to the Algonquin City Gate benchmark price due to the proximity of the offshore production platform to New England. The USA Operations realized prices generally reflect NYMEX and WTI benchmark prices. 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)    2016        2015        2014    

Natural Gas

        

NYMEX ($/MMBtu)

   $ 2.46         $ 2.66         $ 4.41     

AECO (C$/Mcf)

     2.09           2.77           4.42     

Algonquin City Gate ($/MMBtu)

     3.10           4.74           8.06     

Oil

        

WTI ($/bbl)

   $       43.32         $       48.80         $       93.00     

Edmonton Light Sweet (C$/bbl)

     52.98           57.21           94.57     

 

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Production Volumes and Realized Prices

 

      Production Volumes (1)             Realized Prices (2)  
      2016         2015      2014              2016         2015      2014   

Natural Gas (MMcf/d, $/Mcf)

                    

Canadian Operations

                   966           971        1,378          $             1.77         $ 2.75      $ 4.89   

USA Operations

     417           664        972            2.29           2.60        4.62   

Total

     1,383           1,635        2,350            1.93           2.69        4.78   

Oil (Mbbls/d, $/bbl)

                    

Canadian Operations

     2.0           5.6        13.6                36.32               43.90        82.86   

USA Operations

     71.7           81.4        35.8            38.67           43.31        81.27   

Total

     73.7           87.0        49.4            38.61           43.35        81.71   

NGLs – Plant Condensate (Mbbls/d, $/bbl)

                    

Canadian Operations

     17.6           13.9        9.9            40.97           43.26        82.92   

USA Operations

     2.7           2.9        2.1            32.48           37.39        76.33   

Total

     20.3           16.8        12.0            39.84           42.26        81.77   

NGLs – Other (Mbbls/d, $/bbl)

                    

Canadian Operations

     7.6           8.9        13.7            12.13           7.13        32.14   

USA Operations

     20.5           20.7        11.7            12.53           11.20        32.20   

Total

     28.1           29.6        25.4            12.42           9.98        32.18   

Total NGLs (Mbbls/d, $/bbl)

                    

Canadian Operations

     25.2           22.8        23.6            32.32           29.21        53.41   

USA Operations

     23.2           23.6        13.8            14.86           14.37        38.92   

Total

     48.4           46.4        37.4            23.94           21.66        48.09   

Total Oil & NGLs (Mbbls/d, $/bbl)

                    

Canadian Operations

     27.2           28.4        37.2            32.61           32.10        64.16   

USA Operations

     94.9           105.0        49.6            32.84           36.80        69.54   

Total

     122.1           133.4        86.8            32.79           35.80        67.24   

Total Production (MBOE/d, $/BOE)

                    

Canadian Operations

     188.2           190.2        266.9            13.82           18.84        34.21   

USA Operations

     164.5           215.7        211.6            24.78           25.93        37.53   

Total

     352.7           405.9        478.5                  18.93           22.61        35.67   

Production Mix (%)

                    

Natural Gas

     65           67        82               

Oil & NGLs (3)

     35           33        18                                       

Core Asset Production

                    

Natural Gas (MMcf/d)

     887           838        674               

Oil (Mbbls/d)

     64.1           66.5        26.0               

NGLs – Plant Condensate (Mbbls/d)

     19.2           15.1        7.2               

NGLs – Other (Mbbls/d)

     22.9           21.3        11.1               

Total NGLs (Mbbls/d)

     42.1           36.4        18.3               

Total Oil & NGLs (Mbbls/d)

     106.2           102.9        44.3               

Total Production (MBOE/d)

     254.2           242.6        156.6               

% of Total Encana Production

     72           60        33                                       
(1)

Average daily.

(2)

Average per-unit prices, excluding the impact of risk management activities.

(3)

Includes plant condensate.

 

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As a means of managing commodity price volatility, Encana enters into commodity derivative financial instruments on a portion of its expected natural gas, oil and NGL 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, 2016 can be found in Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Product Revenues

 

Product Revenues

 

($ millions)

  

Natural   

Gas   

     Oil         NGLs (1)         Total     

2014

   $ 4,108          $ 1,475          $ 655          $ 6,238      

Increase (decrease) due to:

           

Production volumes (2)

     (1,391)           695            41            (655)     

Sales prices (2)

     (1,112)           (792)           (329)           (2,233)     

2015

   $       1,605          $       1,378          $       367          $       3,350      

Increase (decrease) due to:

           

Production volumes

     (258)           (209)           24            (443)     

Sales prices

     (369)           (128)           33            (464)     

2016

   $ 978          $ 1,041          $ 424          $ 2,443      
(1)

Includes plant condensate.

(2)

Production volume and sales price variances have been updated to reflect a more detailed product split.

Natural Gas Revenues

2016 versus 2015

Natural gas revenues decreased $627 million compared to 2015 primarily due to:

 

   

Lower average realized natural gas prices of $0.76 per Mcf, or 28 percent, decreased revenues by $369 million. The decrease reflected lower NYMEX, AECO and Algonquin City Gate benchmark prices which were down 8 percent, 25 percent and 35 percent, respectively; and

 

   

Lower average natural gas production volumes of 252 MMcf/d decreased revenues by $258 million. Lower volumes were primarily due to the sales of the Haynesville natural gas assets in the fourth quarter of 2015 (152 MMcf/d), the Gordondale (33 MMcf/d) and DJ Basin assets (20 MMcf/d) in the third quarter of 2016 and natural declines in Piceance (49 MMcf/d), Haynesville (21 MMcf/d) and Deep Panuke (16 MMcf/d), partially offset by successful drilling programs in Montney and Duvernay (66 MMcf/d).

2015 versus 2014

Natural gas revenues decreased $2,503 million compared to 2014 primarily due to:

 

   

Lower average natural gas production volumes of 715 MMcf/d decreased revenues by $1,391 million. Lower volumes were primarily due to the sale of certain assets in Wheatland in the first quarter of 2015 (165 MMcf/d), the sales of the Jonah and East Texas properties in the second quarter of 2014 (144 MMcf/d), the sale of the Bighorn assets in the third quarter of 2014 (135 MMcf/d), natural declines in Haynesville (114 MMcf/d) and Piceance (82 MMcf/d) and shut-in production at Deep Panuke as a result of the implementation of a seasonal operating strategy in 2015 and a higher water production rate (104 MMcf/d), partially offset by successful drilling programs in Montney and Duvernay (118 MMcf/d); and

 

   

Lower average realized natural gas prices of $2.09 per Mcf, or 44 percent, decreased revenues by $1,112 million. The decrease reflected lower NYMEX and AECO benchmark prices which were down 40 percent and 37 percent, respectively.

 

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Oil Revenues

2016 versus 2015

Oil revenues decreased $337 million compared to 2015 primarily due to:

 

   

Lower average oil production volumes of 13.3 Mbbls/d decreased revenues by $209 million. Lower volumes were primarily due to natural declines in the USA Other Upstream Operations (8.3 Mbbls/d) and on Montney oil wells (1.8 Mbbls/d), a reduced capital program in Eagle Ford (4.6 Mbbls/d) and the sales of the DJ Basin (2.1 Mbbls/d) and Gordondale assets (1.0 Mbbls/d) in the third quarter of 2016, partially offset by a successful drilling program in Permian (5.8 Mbbls/d); and

 

   

Lower average realized oil prices of $4.74 per bbl, or 11 percent, decreased revenues by $128 million. The decrease reflected lower WTI and Edmonton Light Sweet benchmark prices which were down 11 percent and 7 percent, respectively.

2015 versus 2014

Oil revenues decreased $97 million compared to 2014 primarily due to:

 

   

Lower average realized oil prices of $38.36 per bbl, or 47 percent, decreased revenues by $792 million. The decrease reflected lower WTI and Edmonton Light Sweet benchmark prices which were down 48 percent and 40 percent, respectively;

partially offset by:

 

   

Higher average oil production volumes of 37.6 Mbbls/d increased revenues by $695 million. Higher volumes were primarily due to the acquisitions of Eagle Ford and the Permian assets (24.2 Mbbls/d) in the second and fourth quarters of 2014, respectively, and successful drilling programs in Eagle Ford and Permian (18.0 Mbbls/d) and the USA Other Upstream Operations (6.0 Mbbls/d), partially offset by the sales of the Bighorn assets and the Company’s investment in PrairieSky Royalty Ltd. (“PrairieSky”) in the third quarter of 2014 (4.7 Mbbls/d), natural declines in the Canadian Operations (3.1 Mbbls/d) and the sales of the Jonah and East Texas properties in the second quarter of 2014 (1.5 Mbbls/d).

NGL Revenues

2016 versus 2015

NGL revenues increased $57 million compared to 2015 primarily due to:

 

   

Higher average realized NGL prices of $2.28 per bbl, or 11 percent, increased revenues by $33 million, mainly reflecting a shift in the NGL production mix to higher value condensate compared to 2015; and

 

   

Higher average NGL production volumes of 2.0 Mbbls/d increased revenues by $24 million. Higher volumes were primarily due to successful drilling programs in the Core Assets (7.8 Mbbls/d), partially offset by the sales of the Gordondale (2.4 Mbbls/d) and DJ Basin assets (2.1 Mbbls/d) in the third quarter of 2016 and natural declines in the USA Other Upstream Operations (1.1 Mbbls/d).

2015 versus 2014

NGL revenues decreased $288 million compared to 2014 primarily due:

 

   

Lower average realized NGL prices of $26.43 per bbl, or 55 percent, decreased revenues by $329 million. The decrease reflected lower WTI and Edmonton Light Sweet benchmark prices which were down 48 percent and 40 percent, respectively;

 

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partially offset by:

 

   

Higher average NGL production volumes of 9.0 Mbbls/d increased revenues by $41 million. Higher volumes were primarily due to successful drilling programs in the Core Assets (12.0 Mbbls/d) and the acquisitions of Eagle Ford (2.6 Mbbls/d) and the Permian assets (4.1 Mbbls/d) in the second and fourth quarters of 2014, respectively, partially offset by the sales of the Bighorn assets (6.5 Mbbls/d) and the Company’s investment in PrairieSky (1.0 Mbbls/d) in the third quarter of 2014.

Gains (Losses) on Risk Management, Net

The following table provides the effects of Encana’s risk management activities on revenues.

 

($ millions, except per-unit amounts as indicated)          2016              2015           2014                    2016              2015          2014    

Realized Gains (Losses) on Risk Management

                  

Commodity Price

                  

Natural Gas ($/Mcf)

   $ 85         $     718      $     (159)          $ 0.17         $ 1.20       $ (0.19)    

Oil ($/bbl)

     271           201        78                 10.07           6.33         4.32     

NGLs (1) ($/bbl)

     -           -        -             (0.04)          -         -     

Other (2)

     5           (2     (3)            -           -         -     

Total ($/BOE)

     361           917        (84)          $ 2.76         $     6.20       $     (0.46)    

Unrealized Gains (Losses) on Risk Management

     (636)          (325     456                

Total Gains (Losses) on Risk Management, Net

   $     (275)        $ 592      $ 372                                        
(1)

Includes plant condensate.

(2)

Other includes realized gains or losses from 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 Operations, 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. For additional information on the Company’s commodity price mitigation program, refer to Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Market Optimization Revenues

Market Optimization revenues relate to activities that provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification.

2016 versus 2015

Market Optimization revenues increased $279 million compared to 2015 primarily due to:

 

   

Higher sales of third-party purchased volumes used for optimization activities ($290 million).

2015 versus 2014

Market Optimization revenues decreased $883 million compared to 2014 primarily due to:

 

   

Lower sales of third-party purchased volumes related to the Company’s 2014 divestiture activities ($593 million) and lower commodity prices ($290 million).

Other Revenues

Other Revenues primarily includes amounts related to the sublease of office space in The Bow office building and interest income generated from holding cash and cash equivalents recorded in the Corporate and Other segment, as well as third party transportation and processing revenues with no associated volumes recorded in the Canadian and USA Operations segments. 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.

 

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Operating Expenses

 

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 gas production revenues. Property taxes are generally assessed based on the value of the underlying assets.

 

     $ millions            $/BOE  
            2016              2015              2014                    2016              2015              2014    

Canadian Operations

   $         23        $           28        $           64          $         0.33        $         0.41        $         0.66    

USA Operations

     76          116          146          $ 1.27        $ 1.47        $ 1.89    

Total

   $ 99        $ 144        $ 210                $ 0.77        $ 0.97        $ 1.20    

2016 versus 2015

Production, mineral and other taxes decreased $45 million compared to 2015 primarily due to:

 

   

Lower production volumes and commodity prices primarily in the USA Operations ($23 million), and the sales of the Haynesville natural gas assets in the fourth quarter of 2015 and the DJ Basin and Gordondale assets in the third quarter of 2016 ($17 million).

2015 versus 2014

Production, mineral and other taxes decreased $66 million compared to 2014 primarily due to:

 

   

The sales of the Jonah and East Texas properties in the second quarter of 2014, the sale of certain assets in Wheatland in the first quarter of 2015, the sales of the Bighorn assets and the Company’s investment in PrairieSky in the third quarter of 2014 ($66 million) and lower commodity prices ($70 million);

partially offset by:

 

   

Higher oil and NGL production volumes due to the acquisitions of Eagle Ford and the Permian assets ($73 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  
      2016        2015        2014              2016        2015        2014    

Canadian Operations

   $ 576        $ 654        $ 826          $         8.35        $ 9.42        $ 8.45    

USA Operations (1)

     260          580          658          $ 4.33        $ 7.37        $ 8.51    

Upstream Transportation and Processing

     836          1,234          1,484          $ 6.48        $         8.33        $         8.49    

Market Optimization (1)

     87          12          -               

Corporate and Other

     (22)         6          12               

Total

   $       901        $       1,252        $       1,496                                       
(1)

Market Optimization includes downstream transportation contracts and commitments, previously included in the USA Operations, that were not transferred with certain property divestitures.

 

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2016 versus 2015

Transportation and processing expense decreased $351 million compared to 2015 primarily due to:

 

   

The renegotiation and expiration of certain transportation contracts ($138 million), the sale of the Haynesville natural gas assets in the fourth quarter of 2015 ($97 million), the sales of the DJ Basin and Gordondale assets in the third quarter of 2016 ($46 million), lower activity in Other Upstream Operations ($38 million), unrealized risk management gains on power financial derivative contracts ($28 million) and the lower U.S./Canadian dollar exchange rate ($25 million);

partially offset by:

 

   

Higher activity primarily in Duvernay and Permian ($24 million).

2015 versus 2014

Transportation and processing expense decreased $244 million compared to 2014 primarily due to:

 

   

The sale of the Bighorn assets in the third quarter of 2014 ($117 million), the lower U.S./Canadian dollar exchange rate ($111 million), the sale of certain assets in Wheatland in the first quarter of 2015 ($44 million), the sales of the Jonah and East Texas properties in the second quarter of 2014 ($43 million), the sale of the Haynesville natural gas assets in the fourth quarter of 2015 ($28 million) and shut-in production at Deep Panuke as a result of the implementation of a seasonal operating strategy in 2015 and a higher water production rate ($21 million);

partially offset by:

 

   

Higher activity in the Core Assets, primarily in Montney, and the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively ($136 million).

Operating

Operating expense includes costs paid by Encana 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  
       2016          2015          2014             2016          2015          2014     

Canadian Operations

   $ 152        $ 152        $ 274           $ 2.16        $ 2.17        $ 2.73     

USA Operations

     394          519          326           $ 6.44        $ 6.55        $ 4.18     

Upstream Operating Expense (1)

             546                  671                  600           $         4.16        $         4.50        $         3.37     

Market Optimization

     35          33          39                

Corporate and Other

     17          19          28                

Total

   $ 598        $ 723        $ 667                                        
(1)

2016 Upstream Operating Expense per BOE includes long-term incentive costs of $0.29/BOE (2015 – a recovery of $0.04/BOE; 2014 – costs of $0.06/BOE).

2016 versus 2015

Operating expense decreased $125 million compared to 2015 primarily due to:

 

   

Cost-saving initiatives ($101 million), lower activity primarily in Other Upstream Operations ($42 million), the sale of the Haynesville natural gas assets in the fourth quarter of 2015 ($28 million) and the sales of the DJ Basin and Gordondale assets in the third quarter of 2016 ($23 million);

partially offset by:

 

   

Higher long-term incentive costs resulting from the increase in Encana’s share price ($55 million). Further information on Encana’s long-term incentives can be found in Note 21 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

 

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2015 versus 2014

Operating expense increased $56 million compared to 2014 primarily due to:

 

   

The acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, and successful drilling programs in these plays during 2015 ($243 million);

partially offset by:

 

   

The sale of certain assets in Wheatland in the first quarter of 2015 ($56 million), the lower U.S./Canadian dollar exchange rate ($36 million), the sales of the Jonah and East Texas properties in the second quarter of 2014 ($28 million), lower long-term incentive costs resulting from the decrease in Encana’s share price ($20 million), the sale of the Bighorn assets in the third quarter of 2014 ($19 million) and lower activity primarily in Other Upstream Operations ($12 million).

Purchased Product

Purchased product includes purchases of natural gas, oil and NGLs from third parties that are used to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification.

 

    $ millions  
     2016        2015        2014    

Market Optimization

  $         586         $         323         $       1,191     

2016 versus 2015

Purchased product expense increased $263 million compared to 2015 primarily due to:

 

   

Higher third-party volumes purchased for optimization activities ($322 million), partially offset by lower commodity prices ($59 million).

2015 versus 2014

Purchased product expense decreased $868 million compared to 2014 primarily due to:

 

   

Lower third-party volumes related to the Company’s 2014 divestiture activities ($583 million) and lower commodity prices ($285 million).

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 fluctuations in 12-month average trailing prices which can affect proved reserves volumes. Impairments, acquisitions, divestitures and foreign exchange rates can also impact the depletion rates. 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  
     2016       2015       2014              2016       2015       2014    

Canadian Operations

  $         260        $ 305        $ 625           $       3.77        $ 4.39        $ 6.40     

USA Operations

    523          1,088          992           $ 8.68        $       13.66        $       12.85     

Upstream DD&A

    783          1,393          1,617           $ 6.06        $ 9.31        $ 9.25     

Market Optimization

    -          -          4              

Corporate and Other

    76          95          124              

Total

  $ 859        $       1,488        $       1,745                                      

 

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2016 versus 2015

DD&A decreased $629 million compared to 2015 primarily due to:

 

   

Lower depletion rates in the Canadian and USA Operations ($334 million), lower production volumes in the USA Operations ($245 million) and the lower U.S./Canadian dollar exchange rate ($17 million).

The depletion rate decreased $3.25 per BOE compared to 2015 primarily due to:

 

   

Ceiling test impairments recognized in the first six months of 2016 in the Canadian and USA Operations and ceiling test impairments recognized in 2015 in the USA Operations, the sale of the DJ Basin assets in the third quarter of 2016, the sale of the Haynesville natural gas assets in the fourth quarter of 2015, the sale of certain assets in Wheatland in the first quarter of 2015 and the lower U.S./Canadian dollar exchange rate.

2015 versus 2014

DD&A decreased $257 million compared to 2014 primarily due to:

 

   

Lower production volumes ($161 million) and a lower depletion rate in the Canadian Operations ($88 million), and the lower U.S./Canadian dollar exchange rate ($101 million);

partially offset by:

 

   

A higher depletion rate ($54 million) and higher production volumes in the USA Operations ($30 million).

The depletion rate increased $0.06 per BOE compared to 2014 primarily due to:

 

   

The acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively;

partially offset by:

 

   

Ceiling test impairments recognized in the first nine months of 2015 in the USA Operations, the sales of the Haynesville natural gas assets and Jonah properties in the fourth quarter of 2015 and second quarter of 2014, respectively, the sales of the Bighorn assets and the Company’s investment in PrairieSky in the third quarter of 2014 and the lower U.S./Canadian dollar exchange rate.

Impairments

Under full cost accounting, the carrying amount of Encana’s natural gas and oil 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  
     2016        2015      2014  

Canadian Operations

  $ 493         $ -       $ -   

USA Operations

    903           6,473         -   

Total

  $     1,396         $     6,473       $               -   

Ceiling test impairments in the table above primarily resulted from 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.

 

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The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.

 

     Natural Gas             Oil  
     

Henry Hub

($/MMBtu)

    

AECO

(C$/MMBtu)

           

WTI

($/bbl)

    

Edmonton

Light Sweet

(C$/bbl)

 

12-Month Average Trailing Reserves Pricing (1)

              

2016

     2.49        2.17           42.75        52.21  

2015

     2.58        2.69           50.28        58.82  

2014

     4.34        4.63                 94.99        96.40  
(1)

All prices were held constant in all future years when estimating net revenues and reserves.

Future ceiling test impairments are difficult to reasonably predict and depend on commodity prices, as well as changes to reserves estimates, future development costs, capitalized costs, unproved property costs and acquisitions. Proceeds received from upstream divestitures are generally deducted from the Company’s capitalized costs and can reduce the likelihood of ceiling test impairments.

The Company has calculated the estimated effects that certain commodity price changes may have had on its ceiling test impairments using the average of the price on the first day of each month from the most recent nine months ended December 31, 2016 and commodity futures prices for the three months ended March 31, 2017 of $47.87 per bbl for WTI, C$58.65 per bbl for Edmonton Light Sweet, $2.92 per MMBtu for Henry Hub, and C$2.57 per MMBtu for AECO. Based on these estimated prices, while holding all other inputs and assumptions in the ceiling test constant, no additional impairments would have been recognized at December 31, 2016 for the Canadian and USA Operations. Due to uncertainties in estimating proved reserves, the resulting implications may not be indicative of Encana’s future development plans, operating or financial results.

The Company believes that the discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are not indicative of the fair market value of Encana’s natural gas and oil properties or the future net cash flows expected to be generated from such properties. The discounted after-tax future net cash flows do not consider the fair market value of unamortized unproved properties, or probable or possible natural gas and liquids reserves. In addition, there is no consideration given to the effect of future changes in commodity prices. Encana manages its business using estimates of reserves and resources based on forecast prices and costs. Additional information on the ceiling test calculation can be found in the Critical Accounting Estimates section of this MD&A under Upstream Assets and Reserve Estimates.

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, restructuring and long-term incentive costs.

 

      2016        2015      2014  

Administrative ($ millions)

   $       309        $ 275      $ 327  

Administrative ($/BOE) (1)

   $ 2.40        $       1.86      $       1.87  
(1)

2016 Administrative expense per BOE includes long-term incentive costs and restructuring costs of $0.93/BOE (2015 – $0.36/BOE; 2014 – $0.35/BOE).

2016 versus 2015

Administrative expense in 2016 increased $34 million from 2015 primarily due to long-term incentive costs resulting from the increase in Encana’s share price ($99 million), partially offset by lower restructuring costs ($30 million), lower salaries and benefits as a result of a lower headcount ($13 million), lower office costs ($12 million) and the lower U.S./Canadian dollar exchange rate ($7 million).

 

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During the first quarter of 2016, Encana completed workforce reductions announced in February 2016 to better align staffing levels and the organizational structure with its reduced capital spending program as a result of the low commodity price environment. Encana incurred restructuring costs of $34 million during 2016 compared to $64 million in 2015. Excluding long-term incentive costs and restructuring costs, administrative expense was $1.47 per BOE in 2016 compared to $1.50 per BOE in 2015. Further information on restructuring costs can be found in Note 20 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2015 versus 2014

Administrative expense in 2015 decreased $52 million from 2014 primarily due to the lower U.S./Canadian dollar exchange rate ($24 million), lower salaries and benefits as a result of lower headcount ($18 million) and lower long-term incentive costs resulting from the decrease in Encana’s share price ($16 million), partially offset by higher restructuring costs ($8 million).

During the second quarter of 2015, Encana revised its plans to align the organizational structure in continued support of the Company’s strategy, which resulted in restructuring costs of $62 million in 2015. Restructuring costs attributable to workforce reductions associated with the 2013 restructuring were $2 million in 2015. Excluding long-term incentive costs and restructuring costs, administrative expense was $1.50 per BOE in 2015 compared to $1.52 per BOE in 2014.

Other (Income) Expenses

 

 

     $ millions  
      2016        2015        2014    

Interest

   $        397         $ 614         $ 654     

Foreign exchange (gain) loss, net

     (210)          1,082           403     

(Gain) loss on divestitures, net

     (390)          (14)          (3,426)    

Other (gains) losses, net

     (58)          27           71     

Total Other (Income) Expenses

   $ (261)        $       1,709         $       (2,298)    

Interest

Interest expense primarily includes interest on Encana’s long-term debt arising from U.S. dollar denominated unsecured notes and balances which are drawn on the Company’s credit facilities. Encana also incurs interest on the Company’s long-term obligation for The Bow office building and capital leases.

2016 versus 2015

Interest expense in 2016 decreased $217 million from 2015 primarily due to a one-time payment of $165 million in the second quarter of 2015 associated with the April 2015 early redemptions of the Company’s $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due January 18, 2018 and lower interest on debt following these redemptions, as well as the early retirement of long-term debt in March 2016 as discussed in the Liquidity and Capital Resources section of this MD&A.

2015 versus 2014

Interest expense in 2015 decreased $40 million from 2014 primarily due to lower interest on debt following the April 2015 early debt redemptions. Interest expense was also impacted by a one-time payment of $165 million associated with the April 2015 redemptions compared to a $125 million one-time outlay in 2014 associated with the early redemption of senior notes assumed in conjunction with the acquisition of Athlon Energy Inc. (“Athlon”).

 

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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. 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.

2016 versus 2015

In 2016, Encana recorded a foreign exchange gain compared to a foreign exchange loss in 2015 primarily due to foreign exchange gains on the translation of U.S. dollar debt issued from Canada compared to losses in 2015 ($884 million) and gains on foreign exchange settlements compared to losses in 2015 ($426 million).

2015 versus 2014

In 2015, Encana recorded higher foreign exchange losses on settlements ($330 million) and on the translation of U.S. dollar debt issued from Canada compared to 2014 ($298 million).

(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 on gains on divestitures can be found in Note 4 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2016

Gain on divestitures in 2016 primarily includes the gain on the sale of the Gordondale assets of approximately $394 million.

2015

Gain on divestitures in 2015 primarily included a gain on the sale of the Encana Place office building located in Calgary of approximately $12 million.

2014

Gain on divestitures in 2014 primarily included the impact of the sales of Encana’s investment in PrairieSky of approximately $2,094 million, the Bighorn assets of approximately $1,014 million and the Jonah properties of approximately $209 million.

Other (Gains) Losses, Net

Other (gains) losses, net primarily includes other non-recurring revenues or expenses, reclamation charges relating to decommissioned assets and earnings/losses from equity investments.

2016

Other gains in 2016 primarily includes 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.

2015

Other losses in 2015 primarily included reclamation charges relating to decommissioned assets of $22 million.

 

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2014

Other losses in 2014 primarily included transaction costs of $40 million associated with the acquisitions of Athlon and Eagle Ford and reclamation charges relating to decommissioned assets of $27 million.

Income Tax

 

 

     $ millions  
      2016      2015     2014    

Current Income Tax Expense (Recovery)

   $ (78    $ (34   $ 243     

Deferred Income Tax Expense (Recovery)

     (598      (2,811     960     

Income Tax Expense (Recovery)

   $ (676    $ (2,845   $ 1,203     

Effective Tax Rate

           41.7%               35.5%              26.0%     

Income Tax Expense (Recovery)

2016 versus 2015

Total income tax recovery decreased $2,169 million compared to 2015 primarily due to:

 

   

Lower non-cash ceiling test impairments and foreign exchange gains;

partially offset by:

 

   

An increase to the valuation allowance recorded against the deferred tax assets in respect of U.S. foreign tax credits and U.S. charitable donations totaling $121 million.

Current income tax recoveries in 2016 and 2015 were primarily due to amounts recorded in respect of prior periods.

2015 versus 2014

Total income tax in 2015 was a recovery of $2,845 million compared to an expense of $1,203 million in 2014 primarily due to:

 

   

Lower net earnings before tax mainly resulting from non-cash ceiling test impairments recognized in 2015, and higher gains on divestitures and unrealized gains on risk management recorded in 2014.

Current income tax expense in 2014 was primarily due to taxes incurred on divestitures.

Effective Tax Rate

Encana’s annual effective tax rate is impacted by earnings, income tax related to foreign operations, the effect of legislative changes, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. The 2016 and 2015 effective tax rates 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 in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As a result, there are tax matters under review. The Company believes that the provision for taxes is adequate.

Additional information on income taxes can be found in Note 7 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

 

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Liquidity and Capital 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 and service debt repayments. At December 31, 2016, $179 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 long-standing practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, issuing new debt or repaying existing debt.

 

($ millions, except as indicated)    2016          2015      2014      

Cash and Cash Equivalents

   $ 834           $ 271       $ 338       

Available Credit Facility – Encana (1)

                     3,000                             2,350                         1,740       

Available Credit Facility – U.S. Subsidiary (1)

     1,500             1,500         1,000       

Total Liquidity

     5,334             4,121         3,078       

Long-Term Debt (2)

     4,198             5,333         7,301       

Total Shareholders’ Equity

     6,126             6,167         9,685       

Debt to Capitalization (%) (3)

     41             46         43       

Debt to Adjusted Capitalization (%) (4)

     23             28         30       
(1)

Collectively, the “Credit Facilities”.

(2)

2015 and 2014 have been restated due to the adoption of ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs”, as discussed below under Financing Activities and in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

(3)

Calculated as long-term debt, including the current portion, divided by shareholders’ equity plus long-term debt, including the current portion.

(4)

A non-GAAP measure which is defined in the Non-GAAP Measures section of this MD&A.

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. As shown in the table above, Debt to Adjusted Capitalization has been trending downwards during the past three years as a result of Encana’s efforts to strengthen its balance sheet through debt repayments. 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.

 

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Sources and Uses of Cash

 

During 2016, Encana primarily generated cash through operating activities, divestitures and a share offering. Proceeds from the divestitures and a portion of the proceeds from the share offering were used to repay indebtedness under the Credit Facilities.

 

($ millions)    Activity Type        2016        2015         2014     

Sources of Cash and Cash Equivalents

           

Cash from operating activities

     Operating         $ 625         $ 1,681          $ 2,667      

Proceeds from divestitures

     Investing           1,262           1,908            4,345      

Proceeds from sale of investment in PrairieSky

     Investing           -           -            2,172      

Proceeds from sale of noncontrolling interest

     Financing           -           -            1,462      

Net issuance of revolving long-term debt

     Financing           -           -            942      

Issuance of common shares, net of offering costs

     Financing           1,129           1,088            -      

Other

     Investing           51           71            321      
                3,067                   4,748                    11,909      

Uses of Cash and Cash Equivalents

           

Capital expenditures

     Investing           1,132           2,232            2,526      

Acquisitions

     Investing           210           70            3,016      

Corporate acquisition

     Investing           -           -            5,962      

Net repayment of revolving long-term debt

     Financing           650           627            -      

Repayment of long-term debt

     Financing           400           1,302            2,152      

Dividends on common shares

     Financing           51           152            202      

Other

     Investing/Financing           66           403            152      
        2,509           4,786            14,010      

Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency

              5           (29)           (127)     

Increase (Decrease) in Cash and Cash Equivalents

            $ 563         $ (67)         $ (2,228)     

Operating Activities

Cash from operating activities can be significantly impacted by fluctuations in commodity prices, operating costs and changes in production volumes. During 2016, cash from operating activities was impacted by the depressed commodity price environment; however, Encana offset some of this impact by reducing cash operating costs, administrative expense and interest expense as well as by executing a successful commodity price mitigation program. Encana expects it will continue to meet the payment terms of its suppliers. Non-GAAP Cash Flow was $838 million in 2016 and was impacted mainly by the items affecting cash from operating activities. The primary items affecting cash from operating activities are discussed below and in the Results of Operations section of this MD&A. Additional information on Non-GAAP Cash Flow can be found in the Non-GAAP Measures section of this MD&A.

2016 versus 2015

Net cash from operating activities in 2016 decreased $1,056 million from 2015 primarily due to:

 

   

Lower realized gains on risk management included in revenues ($556 million), lower realized commodity prices ($464 million), lower production volumes ($443 million) and changes in non-cash working capital ($449 million);

partially offset by:

 

   

Lower transportation and processing expense ($351 million), lower operating expenses and administrative expense, excluding non-cash long-term incentive costs ($240 million), lower interest on long-term debt ($201 million), lower production, mineral and other taxes ($45 million) and a higher current tax recovery ($44 million).

 

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2015 versus 2014

Net cash from operating activities in 2015 decreased $986 million from 2014 primarily due to:

 

   

Lower realized commodity prices ($2,233 million) and lower natural gas production volumes ($1,391 million);

partially offset by:

 

   

Realized gains on risk management included in revenues ($1,001 million), higher liquids production volumes ($736 million), a current tax recovery ($277 million), changes in non-cash working capital ($271 million) and lower transportation and processing expense ($244 million).

Investing Activities

Capital expenditures, acquisitions and divestitures have been Encana’s primary investing activities over the past three years. Capital expenditures have decreased as Encana focused its portfolio on its Core Assets and reduced its capital spending program in response to lower commodity prices. In addition, Encana made some significant acquisitions during 2014 which drove investing activities during that year. Capital expenditures and acquisition and divestiture activity are summarized in Notes 2, 3 and 4 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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). 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.

2015

Net cash used in investing activities in 2015 was $665 million primarily due to capital expenditures, partially offset by proceeds from divestitures. Capital expenditures during 2015 were $2,232 million, of which $1,850 million or 83 percent, was directed to the Core Assets. Capital expenditures exceeded cash from operating activities by $551 million with the difference being funded using proceeds from divestitures.

 

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Divestitures in 2015 were $1,908 million, which primarily included transactions summarized in the table below.

 

Transaction    Location      Closing Date     

Cash Inflows  

($ millions)  

 

Divestitures

        

Sale of certain assets in Wheatland

     Alberta         January 15, 2015       $         467     

Sale of certain natural gas gathering and compression assets in Montney (1)

     British Columbia         March 31, 2015         355     

Sale of Haynesville natural gas assets

     Louisiana         November 12, 2015         769     

 

(1)

Sold to Veresen Midstream Limited Partnership (“VMLP”). Further information regarding VMLP can be found in Note 19 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2014

In 2014, Encana was actively implementing its new strategy under the Company’s new CEO, Doug Suttles and undertook several significant transactions which impacted investing activities. Net cash used in investing activities in 2014 was $4,729 million primarily due to the acquisitions of Eagle Ford and the Permian assets which were primarily funded with cash on hand resulting from divestiture transactions in 2014 as summarized in the table below.

 

Transaction    Location      Closing Date     

Cash Inflows/  

Outflows  

($ millions)  

 

Divestitures

        

Divestiture of Encana’s investment in PrairieSky (1)

     Alberta         September 26, 2014       $         2,172     

Sale of Bighorn assets

     Alberta         September 30, 2014         1,725     

Sale of Jonah properties

     Wyoming         May 12, 2014         1,636     

Sale of East Texas properties

     Texas         June 19, 2014         495     

Acquisitions

        

Acquisition of properties in the Eagle Ford shale formation

     Texas         June 20, 2014       $         2,923     

Acquisition of Athlon Energy Inc. with assets in the Permian Basin (1)

     Texas         November 13, 2014         5,962     

 

(1)

Transactions involved the disposition or acquisition of common shares.

Financing Activities

Net cash used in financing activities over the past three years has been impacted by Encana’s strategy to enhance liquidity and strengthen its balance sheet through debt repayments and common share offerings. The Company has paid dividends each of the past three years, though the dividend paid per common share decreased in 2016.

2016 versus 2015

Net cash used in financing activities in 2016 decreased $1,016 million from 2015. The decrease was primarily due to a lower repayment of long-term debt ($902 million), partially offset by lower cash dividend payments ($101 million).

2015 versus 2014

Net cash used in financing activities in 2015 increased $1,015 million from 2014 primarily due to a net repayment of revolving long-term debt in 2015 compared with a net issuance in 2014 ($1,569 million), and proceeds from the sale of the noncontrolling interest in PrairieSky in 2014 ($1,462 million), partially offset by proceeds from the issuance of common shares ($1,088 million) and lower long-term debt repayments in 2015 ($850 million).

The transactions affecting the changes in financing activities are discussed in more detail below.

2016

Encana’s long-term debt totaled $4,198 million at December 31, 2016 and there was no current portion outstanding. At December 31, 2016, Encana has no long-term debt maturities until 2019 and over 73 percent of the Company’s debt is not due until 2030 and beyond.

 

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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. Further information on the Tender Offers can be found in Note 13 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

During the first quarter of 2016, Encana received a downgrade of its credit rating to below investment grade by Moody’s Investors Service, along with confirmed investment grade credit ratings by Standard & Poor’s Ratings Services, DBRS Limited and Fitch Ratings, Inc. As a result of the split ratings, the Company no longer has access to its U.S. Commercial Paper (“U.S. CP”) program and there was a nominal increase in the cost of short-term borrowings on the Credit Facilities. The Company continues to have full access to the Credit Facilities, which remain committed through July 2020. The split ratings have not impacted the Company’s ability to fund its operations, development activities or capital program.

On August 24, 2016, Encana filed shelf prospectuses in Canada and the U.S., whereby the Company may issue from time to time up to $6.0 billion, or the equivalent in foreign currencies, of 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. (collectively, the “2016 Shelf Prospectuses”). On September 19, 2016, the Company filed prospectus supplements to the 2016 Shelf Prospectuses for a public offering (the “2016 Share Offering”) of 107,000,000 common shares of Encana at a price of $9.35 per common share, as well as an over-allotment option (the “Over-Allotment Option”) granted to the underwriters to purchase up to an additional 16,050,000 common shares, pursuant to an underwriting agreement. The 2016 Share Offering was completed on September 23, 2016 for gross proceeds to Encana of approximately $1.0 billion. After deducting underwriters’ fees and costs of the 2016 Share Offering, the net cash proceeds received were approximately $981 million. The Over-Allotment Option was subsequently exercised in full on October 4, 2016 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). At December 31, 2016, approximately $4.8 billion, or the equivalent in foreign currencies, remained accessible under the 2016 Shelf Prospectuses, the availability of which is dependent upon certain eligibility requirements and market conditions.

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. At December 31, 2016, Encana had no outstanding balance under the Credit Facilities.

2015

Encana’s long-term debt totaled $5,333 million at December 31, 2015 and there was no current portion outstanding. The long-term debt balances reflect Encana’s January 1, 2016 retrospective adoption of ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs”, as described in Notes 1 and 13 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

During 2015, Encana implemented a U.S. CP program which was fully supported by the Credit Facilities and used proceeds from the U.S. CP program and cash on hand to repay outstanding LIBOR loan balances of approximately $1,277 million. At December 31, 2015, Encana had outstanding balances under the Credit Facilities which reflected $440 million of U.S. CP issuances and $210 million of principal obligations related to LIBOR loans.

During 2015, the Company had access to a shelf prospectus which was filed in June 2014 (the “2014 Shelf Prospectus”). In March 2015, the Company filed a prospectus supplement (the “2015 Share Offering”) to the 2014 Shelf Prospectus and issued 98,458,975 common shares of Encana, including common shares issued under

 

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an over-allotment option, for aggregate gross proceeds of approximately C$1.44 billion ($1.13 billion). After deducting underwriters’ fees and costs of the 2015 Share Offering, the net proceeds received were approximately C$1.39 billion ($1.09 billion). The 2014 Shelf Prospectus expired in July 2016.

2014

Encana’s long-term debt totaled $7,301 million at December 31, 2014 and there was no current portion outstanding. The long-term debt balance reflects Encana’s January 1, 2016 retrospective adoption of ASU 2015-03 as described above, which resulted in a $39 million decrease in Long-Term Debt as at December 31, 2014.

As a result of the acquisition of Athlon in November 2014, Encana assumed $500 million 7.375 percent senior notes due April 15, 2021 and $650 million 6.00 percent senior notes due May 1, 2022. In December 2014, Encana completed the redemption of these senior notes using proceeds from the Credit Facilities, resulting in an outstanding balance of $1,277 million under the Credit Facilities at December 31, 2014, which reflected principal obligations related to LIBOR loans. In conjunction with the acquisition, Encana repaid and terminated Athlon’s credit facility with indebtedness outstanding of $335 million. During 2014, Encana recorded net issuances of $942 million from the Credit Facilities.

During the second quarter of 2014, PrairieSky acquired Encana’s royalty business with assets in Clearwater located predominantly in central and southern Alberta. Subsequently, Encana completed the initial public offering of 59.8 common shares of PrairieSky for aggregate gross proceeds of approximately C$1.67 billion ($1.54 billion).

In the first half of 2014, Encana completed a cash tender offer and consent solicitation for the Company’s $1.0 billion 5.80 percent notes with a maturity date of May 1, 2014 and the redemption of all notes not tendered in the tender offer.

Dividends

Encana pays quarterly dividends to shareholders at the discreti