Edgar Filing: ENCANA CORP

10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X]

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

For the fiscal year ended December 31, 2017

[ ]

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		98-0355077
(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 (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer [X]		Accelerated filer [ ]
Non-accelerated filer [ ] (Do not check if a smaller reporting company)		Smaller reporting company [ ]
		Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes [ ] No [X]


Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2017		$ 8,563,240,884
Number of registrant’s common shares outstanding as of February 16, 2018		973,123,364

Documents Incorporated by Reference

Portions of registrant’s definitive proxy statement (“Proxy Statement”) for the registrant’s 2018 annual meeting of shareholders to be held May 1, 2018 (to be filed with the Securities and Exchange Commission prior to April 30, 2018) are incorporated by reference in Part III of this Annual Report on Form 10-K.

ENCANA CORPORATION

FORM 10-K

TABLE OF CONTENTS


PART I

Items 1 and 2. Business and Properties			5
Item 1A. Risk Factors			24
Item 1B. Unresolved Staff Comments			32
Item 3. Legal Proceedings			32
Item 4. Mine Safety Disclosures			32

PART II

Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities			33
Item 6. Selected Financial Data			36
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			37
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			66
Item 8. Financial Statements and Supplementary Data			68
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			126
Item 9A. Controls and Procedures			126
Item 9B. Other Information			126
PART III

Item 10. Directors, Executive Officers and Corporate Governance			127
Item 11. Executive Compensation			127
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			127
Item 13. Certain Relationships and Related Transactions, and Director Independence			127
Item 14. Principal Accounting Fees and Services			127

PART IV
Item 15. Exhibits and Financial Statement Schedules			128
Signatures			132

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.

“TSX” means Toronto Stock Exchange.

“U.S.” or “United States” or “USA” means United States of America.

“U.S. GAAP” means U.S. Generally Accepted Accounting Principles.

“WTI” means West Texas Intermediate.

CONVERSIONS

In this Annual Report on Form 10-K, a conversion of natural gas volumes to BOE is on the basis of six Mcf to one bbl. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value, particularly if used in isolation.

CONVENTIONS

Unless otherwise specified, all dollar amounts are expressed in U.S. dollars, all references to “dollars”, “$” or “US$” are to U.S. dollars and all references to “C$” are to Canadian dollars. All amounts are provided on a before tax basis, unless otherwise stated. In addition, all information provided herein is presented on an after royalties basis.

The term “liquids” is used to represent oil, NGLs and condensate. The term “liquids rich” is used to represent natural gas streams with associated liquids volumes. The term “play” is used to describe an area in which hydrocarbon accumulations or prospects of a given type occur. Encana’s focus of development is on hydrocarbon accumulations known to exist over a large areal expanse and/or thick vertical section and are developed using hydraulic fracturing. This type of development typically has a lower geological and/or commercial development risk and lower average decline rate, when compared to conventional development.

The term “core asset” refers to plays that are the focus of the Company’s current capital investment and development plan. The Company continually reviews funding for development of its plays based on strategic fit, profitability and portfolio diversity and, as such, the composition of plays identified as a core asset may change over time.

References to information contained on the Company’s website at www.encana.com are not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

FORWARD-LOOKING STATEMENTS AND RISK

This Annual Report on Form 10-K and documents incorporated herein by reference contain certain forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements include: composition of the Company’s core assets, including the allocation of capital and focus of development plans; growth in long-term shareholder value; vision to being a leading North American resource play company; statements with respect to the Company’s strategic objectives including capital allocation strategy, focus of investment, growth of high margin liquids volumes, operating and capital efficiencies and ability to preserve balance sheet strength; ability to lower costs and improve efficiencies to achieve competitive advantage, including benefits of integrated supply chain model and self-sourcing; ability to repeat and deploy successful practices across the Company’s multi-basin portfolio; balancing commodity portfolio; anticipated commodity prices; success of and benefits from technology and innovation, including cube development approach, precision well targeting and advanced completion designs; reduced dependence on fresh water requirements and anticipated water infrastructure; ability to accelerate activity levels; ability to optimize well and completion designs, including changes to lateral lengths drilled, stage, well spacing and stacking optimization; future well inventory; anticipated drilling, number of drilling rigs and the success thereof; anticipated drilling costs and cycle times; anticipated proceeds and future benefits from various joint venture, partnership and other agreements; expected timing for construction of facilities and costs thereof; expansion of future midstream services; estimates of reserves and resources; expected production and product types; ability to replicate successful test wells to future production; statements regarding anticipated cash flow, non-GAAP cash flow margin and leverage ratios; anticipated cash and cash equivalents; anticipated hedging and outcomes of risk management program, including ability to leverage marketing fundamentals expertise, exposure to certain commodity prices and foreign exchange, amount of hedged production, market access and physical sales locations; impact of changes in laws and regulations, including recent U.S. tax reform and potential changes to free trade agreements; compliance with environmental legislation and claims related to the purported causes and impact of climate change, and the costs therefrom; adequacy of provisions for abandonment and site reclamation costs; financial flexibility and discipline; access to cash and cash equivalents and other methods of funding; ability to meet financial obligations, manage debt and financial ratios, finance growth and compliance with financial covenants; impact to the Company as a result of 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; managing capital structure including adjustments to capital spending or dividends, issuing debt or equity, purchasing shares through a normal course issuer bid (“NCIB”) or repaying existing debt; the Company’s planned NCIB, including amounts and number of shares to be acquired, anticipated timeframe, method and location of purchases, and source of

funding thereof; adequacy of the Company’s provision for taxes and legal claims; projections and expectation of meeting the targets contained in the Company’s corporate guidance and five-year plan; ability to manage cost inflation and expected cost structures, including expected operating, transportation and processing and administrative expenses; competitiveness and pace of growth of the Company’s assets within North America and against its peers; outlook of oil and gas industry generally and impact of geopolitical environment; returns from the Company’s core assets; anticipated capital spending plans and source of funding thereof; anticipated staffing levels; expected future interest expense; the Company’s commitments and obligations; statements with respect to future ceiling test impairments; and the possible impact and timing of accounting pronouncements, rule changes and standards.

Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; ability to access credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance, five-year plan and as specified herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of the Company’s drive to productivity and efficiencies; results from innovations; expectation that counterparties will fulfill their obligations under the gathering, midstream and marketing agreements; access to transportation and processing facilities where Encana operates; assumed tax, royalty and regulatory regimes; and expectations and projections made in light of, and generally consistent with, Encana’s historical experience and its perception of historical trends, including with respect to the pace of technological development, benefits achieved and general industry expectations.

Risks and uncertainties that may affect these business outcomes include: ability to generate sufficient cash flow to meet obligations; commodity price volatility; ability to secure adequate transportation and potential pipeline curtailments; variability and discretion of Encana’s board of directors (the “Board of Directors”) to declare and pay dividends, if any; timing and costs of well, facilities and pipeline construction; business interruption, property and casualty losses or unexpected technical difficulties, including impact of weather; counterparty and credit risk; impact of a downgrade in credit rating and its impact on access to sources of liquidity; fluctuations in currency and interest rates; risks inherent in the Company’s corporate guidance; failure to achieve cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential lawsuits and regulatory actions made against the Company; impact of disputes arising with its partners, including suspension of certain obligations and inability to dispose of assets or interests in certain arrangements; the Company’s ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities, including future net revenue estimates; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as “partnerships” or “joint ventures” and the funds received in respect thereof which Encana may refer to from time to time as “proceeds”, “deferred purchase price” and/or “carry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks described in Item 1A. Risk Factors of this Annual Report on Form 10-K and risks and uncertainties impacting Encana’s business as described from time to time in the Company’s other periodic filings with the SEC incorporated by reference in this Annual Report on Form 10-K.

Although the Company believes the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above and in the documents incorporated by reference herein are not exhaustive. Forward-looking statements are made as of the date of this document (or, in the case of a document incorporated by reference, the date of such document incorporated by reference) and, except as required by law, the Company undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained or incorporated by reference in this Annual Report on Form 10-K are expressly qualified by these cautionary statements.

The reader should read carefully the risk factors described in 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.

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 oil, NGL and natural gas producing plays. Encana’s operations also include the marketing of oil, NGLs and natural gas. 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. The public may read any document Encana files with or furnishes to the SEC at the SEC’s public reference room at 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.

STRATEGY

Encana’s vision is to be a leading North American resource play company that is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. Objectives that support the execution of the Company’s strategy include:

Disciplined capital allocation strategy to core assets

Focused investment on growing high margin liquids volumes

Maximizing profitability through operational and capital efficiencies

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 oil and natural gas resources within the plays. Encana continually strives to lower costs and improve efficiencies to achieve competitive advantage through

technology and innovation. Capital and operating efficiencies are achieved by repeating and deploying successful practices across the Company’s multi-basin portfolio.

Encana’s capital investment strategy is focused on quality growth from a limited number of core, high margin and scalable projects, while balancing the commodity portfolio and optimizing performance from the remainder of the Company’s resource base. In addition, Encana leverages its market fundamentals expertise by actively monitoring and managing market volatility and diversifying price and market access risks to enhance the Company’s margins.

During 2017, the oil and natural gas industry continued to experience commodity price volatility. In spite of this trend, Encana has continued to execute on its strategy by focusing capital investment to core assets with high margin liquids and future growth potential and divesting of non-strategic assets. Moreover, the Company focused on lowering overhead costs and enhancing capital and operating efficiencies by leveraging technology and innovation to maximize efficiencies and results. Encana also focused on reducing costs by leveraging its integrated supply chain model by self-sourcing key drilling and completions consumables to obtain scale advantages from negotiating better contract pricing as well as security of supply services. Through continued execution of its strategy, Encana is well positioned for growth in the current price environment. For additional discussion on the Company’s results, see Item 7 of this Annual Report on Form 10-K.

REPORTING SEGMENTS

Encana’s predominant operations are focused on the finding and development of oil, NGL and natural gas reserves. The Company is also focused on creating and capturing additional value through its market optimization segment. The Company conducts a substantial portion of its business through subsidiaries. Encana’s operating and reportable segments are: (i) Canadian Operations; (ii) USA Operations; and (iii) Market Optimization.

Canadian Operations includes the exploration for, development of, and production of oil, NGLs, natural gas and other related activities within Canada. Core assets that are part of Encana’s strategic development focus include: Montney in northeast British Columbia and northwest Alberta and Duvernay in west central Alberta. Other Upstream Operations comprise assets that are not part of Encana’s current strategic focus and primarily include: Wheatland in southern Alberta, Horn River in northeast British Columbia and Deep Panuke located offshore Nova Scotia.

USA Operations includes the exploration for, development of, and production of oil, NGLs, natural gas and other related activities within the U.S. Core assets that are part of Encana’s strategic development focus include: Eagle Ford in south Texas and Permian in west Texas. Other Upstream Operations comprise assets that are not part of Encana’s current strategic focus and primarily includes San Juan in northwest New Mexico.

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, 2017.

LOGO

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 that are not part of Encana’s current strategic focus. Base plays are managed to generate cash flows and focus on enhancing operational efficiency and cost reductions rather than development programs. Option value plays may receive funding for exploration or development based on strategic fit, play profitability driven by price and energy fundamentals and portfolio diversity.

Canadian Operations

Overview: In 2017, the Canadian Operations had total capital investment of approximately $426 million and drilled approximately 117 net wells all of which were in Montney and Duvernay. Production averaged approximately 29.5 Mbbls/d of oil and NGLs and approximately 838 MMcf/d of natural gas. At December 31, 2017, the Canadian Operations had an established land position in Canada of approximately 1.7 million net acres including approximately 1.2 million net undeveloped acres. In addition, the Canadian Operations accounted for 38% of production sales during 2017 and 59% of total proved reserves as at December 31, 2017.

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, 2017)	Gross	Net	Gross	Net	Gross	Net	Average Working Interest
Montney	560	357	718	451	1,278	808	63%
Duvernay	105	44	541	330	646	374	58%
Other Upstream Operations ⁽¹⁾	229	157	622	381	851	538	63%
Total Canadian Operations	894	558	1,881	1,162	2,775	1,720	62%

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


Producing Wells	Oil		Natural Gas		Total
(number of wells at December 31, 2017) ⁽¹⁾	Gross	Net	Gross	Net	Gross	Net
Montney	6	5	1,282	1,173	1,288	1,178
Duvernay	11	4	156	78	167	82
Other Upstream Operations ⁽²⁾	18	12	609	505	627	517
Total Canadian Operations	35	21	2,047	1,756	2,082	1,777

(1) Figures exclude wells capable of producing, but not producing.

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


			NGLs
Production	Oil (Mbbls/d)		Plant Condensate (Mbbls/d)		Other (Mbbls/d)		Total (Mbbls/d)		Natural Gas (MMcf/d)
(average daily)	2017	2016	2017	2016	2017	2016	2017	2016	2017	2016
Montney ⁽¹⁾	0.2	1.9	14.6	10.4	4.5	6.2	19.1	16.6	644	735
Duvernay	0.2	-	8.3	7.1	1.3	1.2	9.6	8.3	64	54
Other Upstream Operations ⁽²⁾	-	0.1	0.2	0.1	0.2	0.2	0.4	0.3	130	177
Total Canadian Operations	0.4	2.0	23.1	17.6	6.0	7.6	29.1	25.2	838	966

(1)	During 2016, Encana divested of the Gordondale assets in Montney. Prior to the disposition, production from Gordondale averaged 1.6 Mbbls/d of oil, 3.7 Mbbls/d of NGLs and 45 MMcf/d of natural gas.

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

Montney

Montney is primarily a condensate rich natural gas play located in northeast British Columbia and northwest Alberta. While Encana is currently targeting the development of condensate rich locations in the Montney formation, the acreage comprising the Montney play also includes landholdings with incremental producing formations such as Cadomin and Doig. In 2017, total production from the play averaged approximately 19.3 Mbbls/d of oil and NGLs and approximately 644 MMcf/d of natural gas. As at December 31, 2017, Encana controlled approximately 808,000 net acres in the play.

During 2017, Encana continued to focus development in the Montney formation, which is characterized by up to six stacked horizons spanning over 1,000 feet of stratigraphy and is being developed exclusively with horizontal well technology. At December 31, 2017, Encana held a large position in the Montney formation of approximately 475,000 net acres, including 259,000 net undeveloped acres and production averaged approximately 19.1 Mbbls/d of oil and NGLs and approximately 567 MMcf/d of natural gas.

Significant efficiency improvements with respect to Montney drilling and completions have been achieved using the cube development approach. In addition to utilizing larger multi-well pads and simultaneous use of multiple drilling rigs, Encana also focused on tighter well spacing, increased completions intensity and reducing costs. In 2017, Encana drilled approximately 108 net horizontal wells with lateral lengths ranging from approximately 3,200 to 12,800 feet and tighter inter-well spacing ranging from approximately 490 to 880 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change. The Company also continued to focus on reducing water costs through its centralized water hub by re-using produced water from drilling operations and utilizing otherwise unusable saline water from a subsurface water aquifer.

As at December 31, 2017, Encana has access to natural gas processing capacity of approximately 1,200 MMcf/d, of which approximately 1,000 MMcf/d is under contract with third parties under varying terms and duration and approximately 215 MMcf/d is owned by the Company. Encana also has access to gathering and compression capacity of approximately 1,300 MMcf/d, of which approximately 1,200 MMcf/d is under contract with third parties under varying terms and duration and approximately 100 MMcf/d is owned by the Company. During the fourth quarter of 2017, access to liquids handling capacity increased due to three new facilities that provide compression and processing under contract with third parties.

Encana has a partnership agreement with a subsidiary of Mitsubishi Corporation (“Mitsubishi”), the Cutbank Ridge Partnership (“CRP”), to jointly develop certain lands predominately in 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$2.5 billion has been received as of December 31, 2017. 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$0.4 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 until the remaining investment commitment is satisfied.

Duvernay

Duvernay is a liquids rich shale gas play located in west central Alberta and includes properties that are primarily located in the Duvernay formation, but also holds potential in other overlapping formations such as the Montney. As at December 31, 2017, Encana controlled approximately 374,000 net acres in the play.

The Duvernay formation within the play primarily comprises approximately 332,000 net acres, including 290,000 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 multi-well pad horizontal drilling technology. During 2017, Encana focused on efficient development to fill existing processing capacity, reducing drilling days and leveraging successful advanced completions designs to maximize well productivity. Encana also drilled approximately 9 net wells during the year with lateral lengths ranging from approximately 6,400 to 10,800 feet with inter-well spacing averaging approximately 1,000 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change. In 2017, production averaged approximately 9.8 Mbbls/d of oil and NGLs and approximately 64 MMcf/d of natural gas. In addition, Encana focused on reducing operating costs by approximately 15 percent since 2016 primarily from the automation and centralized monitoring of wells and facilities and lowering of water handling costs by utilizing existing infrastructure to dispose of water to plant site disposal wells, eliminating costs to truck disposal water to third party disposal sites.

Encana holds an approximate 50.1 percent ownership in three Simonette natural gas processing plants and the associated gathering and compression, of which Encana’s share of natural gas processing capacity is approximately 90 MMcf/d with NGLs production capacity of approximately 18.0 Mbbls/d.

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, of which the investment was substantially received as of December 31, 2017. In February 2018, Encana received the final investment from PetroChina, satisfying the commitment under the agreement.

Other Upstream Operations:

Wheatland

Wheatland is located in southern Alberta and includes producing horizons primarily in the coals and sands of the Cretaceous Edmonton and Belly River Groups. In the fourth quarter of 2017, Encana divested of approximately 511,000 net acres and approximately 4,720 net wells in the play. As at December 31, 2017, Encana had approximately 525 gross producing wells (approximately 464 net producing wells) and controlled approximately 207,000 net acres in the play. During 2017, Encana

focused on play optimization, reducing production declines and lowering operating costs. In 2017, natural gas production from the remaining properties averaged approximately 6 MMcf/d.

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 2017, Encana’s natural gas production averaged approximately 49 MMcf/d. As at December 31, 2017, Encana had approximately 97 gross producing horizontal wells (49 net producing horizontal wells) and controlled approximately 164,000 net acres, which includes 143,000 net undeveloped acres in the Horn River Basin shales. Encana owns an interest in natural gas compression capacity in Horn River of approximately 285 MMcf/d at various facilities in the area. Encana has a 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 2017, natural gas production averaged approximately 19 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, under a seasonal operating strategy. At December 31, 2017, 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.

USA Operations

Overview: In 2017, the USA Operations had total capital investment of approximately $1,358 million and drilled approximately 168 net wells. Production averaged approximately 75.9 Mbbls/d of oil, approximately 23.7 Mbbls/d of NGLs and approximately 266 MMcf/d of natural gas. At December 31, 2017, the USA Operations had an established land position of approximately 399,000 net acres including approximately 119,000 net undeveloped acres. In addition, the USA Operations accounted for 62% of production sales during 2017 and 41% of total proved reserves as at December 31, 2017.

During 2017, Encana divested of approximately 550,000 net acres in Piceance located in northwestern Colorado for proceeds of approximately $605 million, after closing adjustments and the sale of approximately 144,000 net acres in Tuscaloosa Marine Shale (“TMS”) located in east Louisiana and west Mississippi.

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, 2017)	Gross	Net	Gross	Net	Gross	Net	Average Working Interest
Eagle Ford	44	42	1	1	45	43	96%
Permian	97	86	44	32	141	118	84%
Other Upstream Operations ⁽¹⁾	251	152	153	86	404	238	59%
Total USA Operations	392	280	198	119	590	399	68%

(1) Other Upstream Operations primarily includes San Juan.


Producing Wells	Oil		Natural Gas		Total
(number of wells at December 31, 2017) ⁽¹⁾	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	424	411	59	55	483	466
Permian	1,645	1,541	-	-	1,645	1,541
Other Upstream Operations ⁽²⁾	119	68	259	179	378	247
Total USA Operations	2,188	2,020	318	234	2,506	2,254

(1) Figures exclude wells capable of producing, but not producing.

(2) Other Upstream Operations primarily includes San Juan.


			NGLs
Production	Oil (Mbbls/d)		Plant Condensate (Mbbls/d)		Other (Mbbls/d)		Total (Mbbls/d)		Natural Gas (MMcf/d)
(average daily)	2017	2016	2017	2016	2017	2016	2017	2016	2017	2016
Eagle Ford	30.8	32.4	1.4	0.6	6.8	6.6	8.2	7.2	51	48
Permian	41.4	29.8	1.5	1.1	12.1	8.9	13.6	10.0	67	50
Other Upstream Operations ^{(1, 2)}	3.7	9.5	0.3	1.0	1.6	5.0	1.9	6.0	148	319
Total USA Operations	75.9	71.7	3.2	2.7	20.5	20.5	23.7	23.2	266	417

(1) Other Upstream Operations primarily includes San Juan.

(2) Other Upstream Operations includes production from Piceance and TMS which were divested in 2017 and from DJ Basin which was divested in 2016.

Eagle Ford

Eagle Ford is a tight oil play located in south Texas in the Karnes and Atascosa counties. The focus is on the development of the thickest portion of the Eagle Ford shale in the Karnes Trough, where Encana holds a largely contiguous position. At December 31, 2017, Encana controlled approximately 43,000 net acres in the play. Encana is focused on developing the lower Eagle Ford exclusively using horizontal drilling, as well as optimizing upper Eagle Ford and Austin Chalk targets. During 2017, Encana drilled approximately 37 net wells in the area with lateral lengths ranging from approximately 2,600 to 6,800 feet with an average measured total depth of approximately 16,700 feet. Production averaged approximately 30.8 Mbbls/d of oil, approximately 8.2 Mbbls/d of NGLs and approximately 51 MMcf/d of natural gas during the year.

During 2017, Encana continued to focus on precision well targeting, spacing and stacking optimization and improving completions designs. Performance improvements were achieved from optimizing fracture complexity by driving down stage spacing and cluster spacing to less than 20 feet, while optimizing cluster efficiency through thin fluids design, resulting in

increased well productivity and optimized capital efficiency. In addition, Encana expanded development activity in the Austin Chalk, drilling 12 net horizontal wells in 2017. As Encana continues to optimize development and apply advanced completions designs, lateral lengths drilled, cluster spacing and well spacing may change. Encana also focused on reducing operating costs by negotiating better contract pricing, optimizing artificial lift systems and streamlining well interventions.

The play is located within close proximity to markets and has a well-developed infrastructure. Oil and natural gas production is gathered at various production facilities, with the majority of the oil subsequently transported to sales points by pipeline or trucked from facilities depending on the sales contract. Encana has access to firm natural gas gathering capacity of up to approximately 52 MMcf/d and firm processing capacity of up to approximately 72 MMcf/d with third parties under varying terms and duration. Encana utilizes interruptible capacity arrangements for excess production.

Permian

Permian is a tight oil play located in west Texas in the Midland, Martin, Howard, Glasscock and Upton counties. The primary focus is on the development of the Spraberry and Wolfcamp formations in the Midland basin, where Encana holds a large position. At December 31, 2017, Encana controlled approximately 118,000 net acres in the play. The properties are characterized by exposure of up to 11 potential producing horizons spanning approximately 4,000 feet of stratigraphy (also referred to as “stacked pay”), an extensive production history and mature infrastructure. In 2017, production averaged approximately 41.4 Mbbls/d of oil, approximately 13.6 Mbbls/d of NGLs and approximately 67 MMcf/d of natural gas.

During 2017, Encana focused on maximizing efficiency improvements at an industrial scale and maximizing resource recovery by accessing layers of the stacked pay simultaneously using the cube development approach. This approach utilizes large multi-well pads, multi- rig spreads and frac spreads running in parallel to optimize cycle times, increase capital efficiency and reduce costs through economies of scale from higher utilization of services and consumable supplies, while minimizing the development or surface footprint. Encana also reduced capital costs through centralized wellsite facilities and water infrastructure. Encana also focused on increasing well productivity by optimizing completions designs, with precision targeting of the wells drilled, tighter cluster spacing and using cleaner and thinner fluids to maximize fracture complexity. During 2017, Encana drilled 126 horizontal net wells with lateral lengths ranging from approximately 4,200 to 11,000 feet at a measured average total depth of approximately 17,300 feet with well spacing ranging from approximately 360 to 660 feet. As Encana continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change.

Oil and natural gas facilities include field gathering systems, storage batteries, saltwater disposal systems, separation equipment and pumping units. The majority of Encana’s acreage and associated oil production is dedicated to a pipeline gathering agreement, which has a total remaining term of 12 years including optional renewal terms. In the event of pipeline capacity constraints, Encana’s oil production is trucked by a third party. Natural gas is delivered by Encana to the purchaser’s meter and pipeline interconnection point in the field.

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 its land position almost exclusively in the oil window of the play. Development is focused on the liquids in Tocito and El Vado formations within the play. At December 31, 2017, Encana controlled approximately 198,000 net acres in the play, which includes 69,000 net undeveloped acres. During 2017, Encana drilled 3 horizontal net wells in the Tocito and 1 horizontal net wells in El Vado with lateral lengths ranging from approximately 3,600 to 7,900 feet at a measured average total depth of approximately 12,300 feet. In 2017, Encana applied successful drilling and completions strategies from its other plays, drilling the wells in a transverse orientation utilizing thinner fluids and tighter cluster spacing to optimize fracture complexity. Encana is currently evaluating the stacked pay potential and future well inventory of the play from the well spacing trial. Production averaged approximately 3.9 Mbbls/d of oil and NGLs and approximately 9 MMcf/d of natural gas during the year. Encana has access to natural gas processing capacity of up to approximately 50 MMcf/d under a dedication agreement with a third party.

PROVED RESERVES AND OTHER OIL AND GAS INFORMATION

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

Encana’s Vice-President, Corporate Reserves 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 Encana’s internal policies that prescribe procedures and standards to be followed for preparing, estimating and recording reserves, which includes updating the Company’s reserves manual, and also conducts periodic internal audits of the procedures, records and controls relating to the preparation of reserves estimates. Encana’s QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the review of the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group. The Corporate Reserves Group also oversees the engagement of independent qualified reserves evaluators (“IQREs”) or independent qualified reserves auditors (“IQRAs”), if any, retained by the Company.

As a member of the Corporate Reserves Group, the Company’s Director, Corporate Reserves reports to Encana’s Vice-President, Corporate Reserves 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, is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and the Society of Petroleum Evaluation Engineers (Calgary Chapter).

Annually, each play is reviewed in detail by the QREs, the Corporate Reserves Group, the Company’s executive officers and an internal Reserves Review Committee, as appropriate. The Corporate Reserves Group also conducts a separate review to ensure the effectiveness of the disclosure controls and that the reserves estimates are free from material misstatement. The final reserves estimates are reviewed by Encana’s Reserves Committee of the Board of Directors (the “Reserves Committee”), for approval by the Board of Directors. The Reserves Committee comprises directors that are independent and familiar with estimating oil and gas reserves and disclosure requirements. The Reserves Committee provides additional oversight to the Company’s reserves process, meeting with management periodically to review the reserves process, the portfolio of properties results and related disclosures. The Reserves Committee is also responsible for reviewing the qualifications and appointment of IQREs or IQRAs, if any, retained by the Company, including recommending the selection of such IQREs or IQRAs to the Board of Directors for its approval, and will meet with such IQREs or IQRAs to review their reports.

For year-ended December 31, 2017, Encana involved IQRAs to audit and review the processes relating to the Company’s internal oil and gas reserve estimates for certain properties. In 2017, McDaniel & Associates Consultants Ltd. audited 75 percent of Encana’s estimated Canadian proved reserves volumes and Netherland, Sewell & Associates, Inc. audited 80 percent of Encana’s estimated U.S. proved reserves volumes. An audit of reserves is an examination of a company’s oil and gas reserves and future net cash flows by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.

Proved oil and gas reserves are those quantities of oil, gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

The Company’s reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in assessments include information obtained directly from the subsurface through wellbores such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. In the case of producing reserves, the emphasis is on decline analysis where volumetric analysis is considered to limit forecasts to reasonable levels. Non-producing reserves are estimated by analogy to producing offsets, with consideration of volumetric estimates of in place quantities. All locations to which proved undeveloped reserves have been assigned are subject to a development plan adopted by Encana’s management. The tools used to interpret the data included proprietary and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir are based on the unique circumstances of each reservoir and the dataset available at the time of the estimate.

In general, estimates of economically recoverable reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of crude oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies, and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development, and operating expenditures with respect to the reserves associated with the Company’s properties may vary from the information presented herein, and such variations could be material.

The SEC regulations require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, Encana’s reserves have been calculated utilizing the 12-month average trailing historical price for each of the years presented prior to the effective date of the report. The 12-month average is calculated as an unweighted average of the first-day-of-the-month price for each month. The reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

Encana does not file any estimates of total net proved reserves with any U.S. federal authority or agency other than the SEC and the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of the Company’s reserves contained in its reports. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of Encana’s reserves that are filed with the SEC, however, the DOE requires reports to include the interests of all owners in wells that Encana operates and to exclude all interests in wells that Encana does not operate. Encana is also required to provide reserves data prepared in accordance with Canadian securities regulatory requirements, specifically National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) which is filed concurrently on SEDAR at www.sedar.com under Encana’s issuer profile. The primary differences between NI 51-101 reporting requirements and SEC requirements include the disclosure of proved and probable reserves estimated using forecast prices and costs, presentation of reserves and production before royalties and granular product type disclosures. The reserves data prepared in accordance 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, 2017 and was prepared as of January 15, 2018. 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.

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 25 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, 2017 and other summary operating data.


	As at December 31, 2017
	Canada		U.S.		Total
Proved Reserves:⁽¹⁾
Oil (MMbbls):
Developed		0.2		104.7		104.9
Undeveloped		-		87.7		87.7
Total		0.2		192.3		192.5
Natural Gas Liquids (MMbbls):
Developed		40.5		41.6		82.1
Undeveloped		74.5		25.8		100.3
Total		115.0		67.5		182.5
Natural Gas (Bcf):
Developed		1,082		243		1,325
Undeveloped		1,053		141		1,195
Total		2,135		384		2,519
Total Proved Reserves (MMBOE):
Developed		221.0		186.8		407.8
Undeveloped		250.0		137.0		387.1
Total		471.0		323.9		794.9
Percent Proved Developed		47%		58%		51%
Percent Proved Undeveloped		53%		42%		49%
Production (MBOE/d)		169.1		144.1		313.2
Capital Investments (millions)		$ 426		$1,358		$1,784
Total Net Producing Wells ⁽²⁾		1,835		2,339		4,174
Standardized Measure of Discounted Net Cash Flows: ⁽³⁾
Pre-Tax (millions)		$1,635		$2,731		$4,366
Taxes (millions)		53		-		53
After-Tax (millions)		$1,582		$2,731		$4,313

(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 25 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K for the standardized measure.

Changes to the Company’s proved reserves during 2017 are summarized in the table below:


	2017
	Oil (MMbbls)		NGLs (MMbbls)		Natural Gas (Bcf)		Total (MMBOE)
Beginning of year ⁽¹⁾		155.6		150.4		2,902		789.7
Revisions and improved recovery ⁽²⁾		(15.8)		(18.1)		(58)		(43.6)
Extensions and discoveries		85.1		72.9		871		303.1
Purchase of reserves in place		0.8		0.4		2		1.5
Sale of reserves in place		(5.4)		(3.8)		(795)		(141.6)
Production		(27.8)		(19.3)		(403)		(114.3)
End of year		192.5		182.5		2,519		794.9
Developed		104.9		82.1		1,325		407.8
Undeveloped		87.7		100.3		1,195		387.1
Total		192.5		182.5		2,519		794.9

(1)	Numbers may not add due to rounding.

(2)	Changes in reserve estimates resulting from application of improved recovery techniques are nil and are included in revisions of previous estimates.

In 2017, Encana’s proved oil and NGLs reserves of 375.0 MMbbls increased 69.0 MMbbls from 2016 primarily due to extensions and discoveries of 158.0 MMbbls in the Permian, Montney, and Eagle Ford and purchase of reserves in place of 1.2 MMbbls, partly offset by production of 47.1 MMbbls, negative revisions and improved recovery of 33.9 MMbbls and by sale of reserves of 9.2 MMbbls. Revisions and improved recovery of oil and NGLs were negative primarily due to negative revisions resulting from changes in the approved development plan of 40.3 MMbbls and forecast changes resulting from well performance of 7.7 MMbbls, partly offset by positive revisions of 14.0 MMbbls from higher 12-month average trailing oil and NGL prices.

In 2017, Encana’s proved natural gas reserves of approximately 2,519 Bcf decreased 383 Bcf from 2016 primarily due to sales of reserves in place of 795 Bcf resulting from the divestiture of the Piceance natural gas play and production of 403 Bcf. Revisions and improved recovery of natural gas were negative primarily due to negative revisions of 258 Bcf resulting from changes in the approved development plan, partly offset by positive revisions of 111 Bcf from higher 12-month average trailing natural gas prices and by positive forecast changes other than price of 89 Bcf. Extensions and discoveries of 871 Bcf were due to successful drilling and delineation of Permian, Montney and Eagle Ford assets.

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, 2017 were WTI: $51.34 per bbl, Edmonton Condensate: C$67.65 per bbl, Henry Hub: $2.98 per MMBtu, and AECO: C$2.32 per MMBtu. Prices for natural gas, oil and NGLs can fluctuate widely.

Proved Undeveloped Reserves

Changes to the Company’s proved undeveloped reserves during 2017 are summarized in the table below:


(MMBOE)	2017
Beginning of year		341.0
Revisions of prior estimates		(98.7	)
Extensions and discoveries		225.7
Conversions to developed		(82.4	)
Purchase of reserves in place		1.5
Sale of reserves in place		-
End of Year		387.1

* Numbers may not add due to rounding.

As of December 31, 2017, there were no proved undeveloped reserves that will remain undeveloped for five years or more.

Revisions of previous estimates of proved undeveloped reserves were revised down by 98.7 MMBOE primarily due to the removal of proved undeveloped locations of 83.3 MMBOE resulting from changes in the development plan related to Montney, Permian, Eagle Ford, and San Juan where specific locations previously planned to be drilled within five years were shifted to a later development timeframe and replaced with different locations that are included in extensions and discoveries. In addition, revisions of previous estimates also included a negative revision of 17.4 MMBOE from decreased well performance, offset by a positive revision of 2.0 MMBOE due to higher commodity prices.

Conversions of proved undeveloped reserves to proved developed status were 82.4 MMBOE, equating to 24 percent of the total prior year-end proved undeveloped reserves. Approximately 70 percent of proved undeveloped reserves conversions occurred in Canada in Montney and Duvernay and 30 percent occurred in the U.S. in Permian and Eagle Ford. Encana spent approximately $427 million to develop proved undeveloped reserves in 2017, of which approximately 40 percent related to the Canadian properties and 60 percent related to the U.S. properties.

Purchases of proved undeveloped reserves of 1.5 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⁾
	Oil (MMbbls)	NGLs (MMbbls)	Natural Gas (Bcf)	Oil ($/bbl)	NGLs ($/bbl)	Natural Gas ($/Mcf)	($/BOE)
2017
Canada ⁽³⁾	0.1	10.6	306	42.33	45.35	2.16	11.46
USA	27.7	8.7	97	49.14	22.30	3.03	9.42
Total	27.8	19.3	403	49.10	34.98	2.37	10.52

2016 ⁽⁴⁾
Canada	0.7	9.2	353	36.32	32.32	1.77	10.69
USA	26.3	8.5	153	38.67	14.86	2.29	10.89
Total	27.0	17.7	506	38.61	23.94	1.93	10.78

2015 ⁽⁴⁾
Canada	2.0	8.3	354	43.90	29.21	2.75	11.74
USA	29.8	8.6	242	43.31	14.37	2.60	13.96
Total	31.8	16.9	596	43.35	21.66	2.69	12.92

(1)	Excludes the impact of commodity derivatives.

(2)	Excludes ad valorem, severance and property taxes.

(3)	Annual production from fields that comprise greater than 15% of the Company’s total proved reserves as at December 31, 2017 related to Dawson North in Montney and included 81 Bcf of natural gas (2016 – 89 Bcf; 2015 – 67 Bcf) and 2.3 MMbbls of NGLs (2016 – 1.3 MMbbls; 2015 – 0.9 MMbbls).

(4)	Encana had no fields where annual production comprised greater than 15% of the Company’s total proved reserves for the periods ended December 31, 2016 and December 31, 2015.

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										Total Revenue
($ millions)	Oil		NGLs		Natural Gas		Other Revenue⁽¹⁾		Gains (losses) on risk management, net
2017
Canada		$ 7		$ 481		$ 662	$	189	$	522	$	1,861
USA		1,360		193		296		773		(40)		2,582
Total		$ 1,367		$ 674		$ 958	$	962	$	482	$	4,443

2016
Canada		$ 26		$ 298		$ 628	$	166	$	(151)	$	967
USA		1,015		126		350		584		(124)		1,951
Total		$ 1,041		$ 424		$ 978	$	750	$	(275)	$	2,918

2015
Canada		$ 90		$ 243		$ 976	$	222	$	166	$	1,697
USA		1,288		124		629		258		426		2,725
Total		$ 1,378		$ 367		$ 1,605	$	480	$	592	$	4,422

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

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.


	Exploratory				Development				Total
	Productive		Dry		Productive		Dry		Productive		Dry
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2017
Canada	2	1	-	-	189	116	-	-	191	117	-	-
USA	-	-	-	-	183	168	-	-	183	168	-	-
Total	2	1	-	-	372	284	-	-	374	285	-	-

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	-

(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, 2017.


	Wells in the Process of Drilling or in Active Completion				Wells Suspended or Waiting on Completion⁽³⁾
	Exploratory		Development		Exploratory		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2017
Canada	-	-	19	13	-	-	57	34
USA	-	-	23	23	-	-	11	11
Total	-	-	42	36	-	-	68	45

(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 exploratory 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, 2017.

Productive Wells^(1,²⁾

Oil⁽³⁾

Natural Gas⁽⁴⁾

Total

Gross

Net

Gross

Net

Gross

Net

2017

Canada

2,121

1,813

2,157

1,835

USA

2,234

2,060

367

279

2,601

2,339

Total

2,270

2,082

2,488

2,092

4,758

4,174

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

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

(3)	Includes 66 gross oil wells (13 net oil wells) containing multiple completions.

(4)	Includes 1,994 gross natural gas wells (1,674 net natural gas wells) containing multiple completions.

The following table summarizes Encana’s developed, undeveloped and total landholdings by geographic area as at December 31, 2017.


Landholdings⁽¹^{- 6)}		Developed		Undeveloped		Total
(thousands of acres)		Gross	Net	Gross	Net	Gross	Net
Canada
Onshore	— Crown	815	503	1,605	975	2,420	1,478
	— Freehold	58	34	217	172	275	206
	— Fee	1	1	3	3	4	4
Offshore	— Crown	20	20	56	12	76	32
Total Canada		894	558	1,881	1,162	2,775	1,720
United States
	— Federal/State	235	140	128	80	363	220
	— Freehold	156	140	65	38	221	178
	— Fee	1	-	5	1	6	1

Total United States		392	280	198	119	590	399
International
Australia		-	-	104	40	104	40
Total International		-	-	104	40	104	40
Total		1,286	838	2,183	1,321	3,469	2,159

(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 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 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 2.2 million net acres, approximately 0.8 million net acres is held by production. The table above includes acreage subject to leases that will expire over the next three years: 2018 – approximately 78,000 net acres; 2019 – approximately 201,000 net acres; and 2020 – approximately 192,000 net acres, if the Company does not establish production or take any other action to extend the terms. For acreage that the Company intends to further develop, Encana will perform operational and administrative actions to continue the lease terms that are set to expire. As a result, it is not expected that a significant portion of the Company’s net acreage will expire before such actions occur.

Title to Properties

As is customary in the oil and natural gas industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time Encana acquires properties. The Company believes that title to all of the various interests set forth in the above table is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in Encana’s operations. The interests owned by Encana may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Company’s operations.

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 oil, NGLs and natural gas, are primarily marketed to refiners, local distributing companies, energy marketing companies and electronic exchanges. Prices received by Encana are based primarily upon prevailing market index prices in the region in which it is sold. Prices are impacted by regional and global supply and demand and by competing fuels in such markets.

Encana’s oil production is sold under short term and evergreen contracts or under dedication agreements, for which prices received by Encana are based primarily upon the prevailing index prices in the relevant region where the product is sold. Encana’s NGLs production is sold under short term and long-term contracts that range up to 11 years, or under dedication arrangements at the relevant market price at the time the product is sold. Encana’s natural gas production is sold under short-term delivery contracts with terms less than 2 years in duration, at the relevant monthly or daily market price at the time the product is sold. Natural gas production from Deep Panuke is sold under a dedication agreement with a third party for prevailing market prices in that region.

Encana also seeks to mitigate the market risk associated with future cash flows by entering into various financial risk management contracts relating to produced oil, NGLs and natural gas. Details of contracts related to Encana’s various financial risk management positions are found in Note 22 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

The Company enters into various contractual agreements to sell oil, NGLs and natural gas, some of which require the delivery of fixed and determinable quantities. As of December 31, 2017, Encana was committed to deliver approximately 3,600 Mbbls of oil and NGLs and approximately 180,000 MMcf of natural gas in the Canadian Operations and approximately 44,000 MMcf of natural gas in the USA Operations with terms under two years.

Certain transportation and processing commitments result in the following financial commitments:


($ millions)	1 Year		2-3 Years		4-5 Years		> 5 years		Total
Transportation & Processing
Canadian Operations
Oil & NGLs		51		137		127		281		596
Natural Gas		406		779		657		1,809		3,651
Total Canadian Operations		457		916		784		2,090		4,247
USA Operations
Oil & NGLs		3		6		6		17		32
Natural Gas		144		449		310		208		1,111
Total USA Operations		147		455		316		225		1,143
Total Canadian and USA Operations		604		1,371		1,100		2,315		5,390

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 oil, NGLs and natural gas for the year ended December 31, 2017, 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 (2016 and 2015 – two customers, Royal Dutch Shell Group and Flint Hills Resources). Encana does not believe that the loss of any single customer would have a material adverse effect on the Company’s financial condition or results of operations. Further information on Encana’s major customers are found in Note 2 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

COMPETITION

The Company’s competitors include national, integrated and independent oil and gas companies, as well as oil and gas marketers and other participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. All aspects of the oil and gas industry are highly competitive and Encana actively competes with other companies in the industry, particularly in the following areas:

Exploration for and development of new sources of oil, NGLs and natural gas reserves;

Reserves and property acquisitions;

Transportation and marketing of oil, NGLs, natural gas and diluents;

Access to services and equipment to carry out exploration, development and operating activities; and

Attracting and retaining experienced industry personnel.

The oil and gas industry also competes with other industries focused on providing alternative forms of energy to consumers. Competitive forces can lead to cost increases or result in an oversupply of oil, NGLs or natural gas.

EMPLOYEES

At December 31, 2017, Encana employed 2,107 employees as set forth in the following table.


	Employees
Canada		1,157
U.S.		950
Total		2,107

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

ENVIRONMENTAL AND REGULATORY MATTERS

As Encana is an owner or lessee and operator of oil and gas properties and facilities in Canada and the United States, the Company is subject to numerous federal, provincial, state, local, tribal and foreign country laws and regulations relating to pollution, protection of the environment and the handling of hazardous materials. These laws and regulations generally require Encana to remove or remedy the effect of its activities on the environment at present and former operating sites, including dismantling production facilities, remediating damage caused by the use or release of specified substances, and require suspension or cessation of operations in affected areas. The following are significant areas of government control and regulation affecting Encana’s operations:

Exploration and Development Activities:

Our operations are subject to federal, tribal, state, provincial and local laws and regulations. These laws and regulations relate to matters that include: acquisition of seismic data; location, drilling and casing of wells; well design; hydraulic

fracturing; well production; use, transportation, storage and disposal of fluids and materials 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 the Company differently, to any material degree, as compared to other companies in the oil and natural gas industry. For further information regarding regulations relating to environmental protection, see Item 1A. Risk Factors of this Annual Report on Form 10-K.

Operating and capital costs incurred to comply with the requirements of these laws and regulations are necessary business costs in the oil and gas industry. As a result, Encana has established policies for continuing compliance with environmental laws and regulations. The Corporate Responsibility, Environment, Health and Safety Committee of the Board of Directors reviews and recommends environmental policy to the Board of Directors for approval and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. The Company has established operating procedures and training programs designed to limit the environmental impact of the Company’s field facilities and identify, communicate and comply with changes in existing laws and regulations. Contingency plans are in place for a timely response to an environmental event and remediation/reclamation programs are in place and utilized to restore the environment. In addition, the Board of Directors is advised of significant contraventions thereof, and receives updates on trends, issues or events which could have a significant impact on the Company.

The Company believes that it is in material compliance with existing environmental and occupational health and safety regulations. Further, the Company believes that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on its business, financial condition or results of operations. In addition, Encana maintains insurance coverage for insurable risks against certain environmental and occupational health and safety risks that is consistent with insurance coverage held by other similarly situated industry participants, but the Company is not fully insured

against all such risks. However, it is possible that developments, such as new or more stringently applied existing laws and regulations as well as claims for damages to property or 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		57	5	President & Chief Executive Officer
Joanne L. Alexander		51	3	Executive Vice-President & General Counsel
Sherri A. Brillon		58	11	Executive Vice-President & Chief Financial Officer
David G. Hill		56	4	Executive Vice-President, Exploration & Business Development
Michael G. McAllister		59	7	Executive Vice-President & Chief Operating Officer
Michael Williams		58	4	Executive Vice-President, Corporate Services
Renee E. Zemljak		53	8	Executive Vice-President, Midstream, Marketing & Fundamentals

(1) As of February 26, 2018

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 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 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.

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).

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, prices and availability of alternate sources of energy (including refined products, coal, and renewable energy initiatives) and by technological advances affecting energy consumption. Oil prices are largely determined by international and domestic supply and demand. Factors which affect oil prices include the actions of the OPEC, world economic conditions, government regulation, political stability in the Middle East and elsewhere, the foreign and domestic supply of oil, the price of foreign imports, the availability of alternate fuel sources, transportation and infrastructure constraints and weather conditions. Historically, NGLs prices have generally been correlated with oil prices, and are determined based on supply and demand in international and domestic NGLs markets.

A substantial or extended decline in the price of natural gas, oil or NGLs could result in a delay or cancellation of existing or future drilling, development or construction programs or curtailment or shut-in of production at some properties or could result in unutilized long-term transportation and drilling commitments, all of which could have an adverse effect on the Company’s revenues, profitability and cash flows.

Natural gas and oil producers in North America, and particularly in Canada, currently receive discounted prices for their production relative to certain international prices due to constraints on their ability to transport and sell such production to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by natural gas and oil producers, including Encana.

On at least an annual basis, Encana conducts an assessment of the carrying value of its assets in accordance with the applicable accounting standards. If natural gas, oil or NGLs prices decline further, the carrying value of Encana’s assets could be subject to financial downward revisions, and the Company’s net earnings could be adversely affected.

Encana’s ability to operate and complete projects is dependent on factors outside of its control which may have a material adverse effect on its business, financial condition or results of operations.

The Company’s ability to operate, generate sufficient cash flows, and complete projects depends upon numerous factors beyond the Company’s control. In addition to commodity prices and continued market demand for its products, these non-controllable factors include general business and market conditions, economic recessions and financial market turmoil, the overall state of the capital markets, including investor appetite for investments in the oil and gas industry generally and the Company’s securities in particular, the ability to secure and maintain cost effective financing for its commitments, legislative, environmental and regulatory matters, changes to free trade agreements, including the North American Free Trade Agreement (“NAFTA”), reliance on industry partners and service providers, unexpected cost increases, royalties, taxes, including the impact of recent U.S. tax reform and potential U.S. Treasury Department regulations and guidance, volatility in natural gas, oil or NGLs prices, the availability of drilling and other equipment, the ability to access lands, the ability to access water for hydraulic fracturing operations, physical impacts from adverse weather conditions and other natural disasters, the availability and proximity of processing and pipeline capacity, transportation interruptions and constraints, technology failures, accidents, the availability of skilled labour and reservoir quality. In addition, some of these risks may be magnified due to the concentrated nature of funding certain assets within the Company’s portfolio of oil and natural gas

properties that are operated within limited geographic areas. As a result, a number of the Company’s assets could experience any of the same risks and conditions at the same time, resulting in a relatively greater impact on the Company’s financial condition and results of operations compared to other companies that may have a more geographically diversified portfolio of properties.

Fluctuations in natural gas, oil or NGLs prices can create fiscal challenges for the oil and gas industry. These conditions have impacted companies in the oil and gas industry and the Company’s spending and operating plans and may continue to do so in the future. There may be unexpected business impacts from market uncertainty, including volatile changes in currency exchange rates, inflation, interest rates, defaults of suppliers and general levels of investing and consuming activity, as well as a potential impact on the Company’s credit ratings, which could affect its liquidity and ability to obtain financing.

The Company undertakes a variety of projects including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may delay expected revenues and project cost overruns could make projects uneconomic.

All of Encana’s operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact the Company’s existing and planned projects.

Encana’s proved reserves are estimates and any material inaccuracies in our reserves estimates or assumptions underlying our reserves estimates could cause quantities and net present value of our reserves to be overstated or understated.

There are numerous uncertainties inherent in estimating quantities of natural gas, oil and NGLs reserves, including many factors beyond the Company’s control. The reserves data in this Annual Report on Form 10-K and other published reserves and resources data represents estimates only. In general, estimates of economically recoverable natural gas, oil and NGLs reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as commodity prices, future operating and capital costs, availability of future capital, historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain, and classifications of reserves and resources are only attempts to define the degree of uncertainty involved.

For those reasons, estimates of the economically recoverable natural gas, oil and NGLs reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Encana’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material. Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

The estimates of reserves included in this Annual Report on Form 10-K are prepared in accordance with SEC regulations and require, subject to limited exceptions, that proved undeveloped reserves may only be classified as proved reserves if the related wells are scheduled to be drilled within five years after the date of booking. Reserves to be developed and produced in the future are based upon certain expectations and assumptions, including the allocation of capital, which may be subject to change. Proved undeveloped reserves may be reclassified to unproved due to delays in the development of reserves, or projects becoming uneconomical due to increases in costs to drill such reserves, or lower future net revenues from further decreases in commodity prices.

Commodity prices used to estimate reserves included in this Annual Report on Form 10-K are calculated as the average oil and natural gas price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. Significant future price changes can have a material effect on the quantity and value of the Company’s proved reserves. The standardized measure of discounted future net cash flows included in this Annual Report on Form 10-K will not represent the current market value of Encana’s

estimated reserves. In addition, these reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

If Encana fails to acquire or find additional reserves, the Company’s reserves and production will decline materially from their current levels.

Encana’s future oil, NGLs and natural gas reserves and production, and therefore its cash flows, are highly dependent upon its success in developing its current reserves base and acquiring, discovering or developing additional reserves. Without reserves additions through exploration, acquisition or development activities, the Company’s reserves and production will decline over time as reserves are depleted.

The business of exploring for, developing or acquiring reserves is capital intensive. In addition, part of Encana’s strategy is focused on a limited number of core assets which results in a concentration of capital and increased potential risks. To the extent that cash flows from the Company’s operations are insufficient and external sources of capital become limited, Encana’s ability to make the necessary capital investments to maintain and expand its natural gas, oil and NGLs reserves and production will be impaired. In addition, there can be no certainty that Encana will be able to find and develop or acquire additional reserves to replace production at acceptable costs.

In addition, Encana’s operations utilize horizontal multi-pad drilling, tighter drill spacing and completions techniques that evolve over time as learnings are captured and applied. The use of this technology may increase the risk of unintentional communication with other wells and the potential for acceleration of current reserves or an increase in recovery factor from the reservoir. If drilling and completions results are less than anticipated, the production volumes may be lower than anticipated.

The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and any changes in such regulation could negatively affect its results of operations.

All phases of the natural gas, oil and NGLs businesses are subject to environmental regulation pursuant to a variety of Canadian, U.S. and other federal, provincial, territorial, tribal, state and municipal laws and regulations (collectively, “environmental regulation”).

Environmental regulation imposes, among other things, restrictions, liabilities and obligations in connection with the use, generation, handling, storage, transportation, treatment and disposal of chemicals, hazardous substances and waste associated with the finding, production, transmission and storage of the Company’s products including the hydraulic fracturing of wells, the decommissioning of facilities and in connection with spills, releases and emissions of various substances to the environment. It also imposes restrictions, liabilities and obligations in connection with the availability and management of fresh, potable or brackish water sources that are being used, or whose use is contemplated, in connection with natural gas and oil operations.

Environmental regulation also requires that wells, facility sites and other properties associated with Encana’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Compliance with environmental regulation can require significant expenditures, including expenditures for clean-up costs and damages arising out of contaminated properties and failure to comply with environmental regulation may result in the imposition of fines and penalties.

Although it is not expected that the costs of complying with environmental regulation will have a material adverse effect on Encana’s financial condition or results of operations, no assurance can be made that the costs of complying with environmental regulation in the future will not have such an effect as discussed below.

Climate Change - A number of federal, provincial and state governments have announced intentions to regulate greenhouse gases and certain air pollutants. These governments are currently developing regulatory and policy frameworks to deliver on their announcements. The Canadian federal government along with certain provinces and territories, including Alberta and British Columbia, have announced a pan-Canadian climate change framework that is consistent with the outcome reached at the 21^st Conference of the Parties in Paris and which includes imposing an economy wide cost on carbon emissions in Canada

by 2023. The Alberta government outlined its Climate Leadership Plan which includes four key areas, one of which is targeting a 45 percent reduction in methane gas emissions from oil and gas operations by 2025, to be achieved through equipment replacement and leak detection and repair regulations. Both Alberta and British Columbia have implemented a provincial carbon tax; Alberta introduced a carbon levy in January 2017 of C$20 per tonne of CO₂e, increasing to C$30 per tonne of CO₂e in 2018 while British Columbia has an established carbon levy of C$30 per tonne of CO₂e, increasing by C$5 per tonne of CO₂e per year starting April 1, 2018 until it reaches C$50 per tonne of CO₂e in 2021. In the United States, the U.S. Environmental Protection Agency (“EPA”) has proposed to delay the implementation of rules currently in effect that regulate methane emissions from the oil and gas industry. As part of the proposed delay, the EPA intends to evaluate whether to regulate oil and gas methane emissions directly or as a co-benefit of regulating volatile organic compounds. Encana’s cost of complying with emerging climate and cost of carbon regulations is not currently forecast to be material to the Company, however as these and additional federal and regional programs are in their early implementation stage or under development, Encana is unable to predict the total future impact of the potential regulations upon its business. Therefore, it is possible that the Company could face future increases in operating costs in order to comply with legislation governing emissions. Further, certain local governments, stakeholders and other groups have made claims against companies in the oil and gas industry, including the Company, relating to the purported causes and impact of climate change. These claims have, among other things, resulted in litigation, shareholder proposals and local ballot initiatives targeted against certain companies and the oil and gas industry generally. As these claims are in their early stages, the Company is unable to assess the impact of such claims on its business, but the defense of such matters may be costly and time consuming and could have a material adverse effect on the Company’s reputation.

Hydraulic Fracturing - The U.S. and Canadian federal governments and certain U.S. state and Canadian provincial governments continue to review certain aspects of the scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. Most of these governments are primarily engaged in the collection, review and assessment of technical information regarding the hydraulic fracturing process and have not provided specific details with respect to any significant actual, proposed or contemplated changes to the hydraulic fracturing regulatory construct. However, certain environmental and other groups continue to suggest that additional federal, provincial, territorial, state and municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process, and have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources.

Further, certain governments in jurisdictions where the Company does not currently operate have considered or implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments have adopted, and others have considered adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs or third party or governmental claims, and could increase the Company’s cost of compliance and doing business as well as reduce the amount of natural gas and oil that the Company is ultimately able to produce from its reserves. The Company recognizes that additional hydraulic fracturing ballot initiatives and/or local rule-making limiting or restricting oil and gas development activities are a possibility in the future.

As these federal and regional programs are in their early implementation stage or under development, Encana is unable to predict the total impact of the potential regulations upon its business. Therefore, it is possible that the Company could face increases in operating costs or curtailment of production in order to comply with legislation governing hydraulic fracturing.

Seismic Activity – Some areas of North America are experiencing increasing localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence 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.

Encana’s risk management activities may prevent the Company from fully benefiting from price increases and expose us to other risks.

The nature of the Company’s operations results in exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company monitors its exposure to such fluctuations and, where the Company deems it appropriate,

utilizes derivative financial instruments and physical delivery contracts to mitigate the potential impact of declines in natural gas, oil or NGLs prices and fluctuations in foreign currency exchange rates.

Under U.S. GAAP, derivative financial instruments that do not qualify or are not designated as hedges for accounting purposes are fair valued with the resulting changes recognized in current period net earnings. The utilization of derivative financial instruments may therefore introduce significant volatility into the Company’s reported net earnings.

The terms of the Company’s various risk management agreements and the amount of estimated production hedged may limit the benefit to the Company of commodity price increases. The Company may also suffer financial loss if the Company is unable to produce natural gas, oil or NGLs, or if counterparties to the Company’s risk management agreements fail to fulfill their obligations under the agreements, particularly during periods of declining commodity prices.

Downgrades in Encana’s credit ratings could increase its cost of capital and limit its access to capital, suppliers or counterparties.

Rating agencies regularly evaluate the Company, basing their ratings of its long-term and short-term debt on a number of factors. This includes the Company’s financial strength as well as factors not entirely within its control, including conditions affecting the oil and gas industry generally and the wider state of the economy. One of the Company’s credit ratings is below an investment-grade credit rating. There can be no assurance that the Company’s other credit ratings will not also be downgraded, including below an investment-grade credit rating.

The Company’s borrowing costs and ability to raise funds are directly impacted by its credit ratings. A downgrade may increase the cost of borrowing under the Company’s existing credit facilities, limit access to private and public markets to raise short-term and long-term debt, and negatively impact the Company’s cost of capital. Further, as a result of one of the Company’s credit ratings being below investment grade, access to the Company’s U.S. commercial paper program has been eliminated.

Credit ratings may also be important to suppliers or counterparties when they seek to engage in certain transactions. Downgrades in one or more of the Company’s credit ratings below investment-grade may require the Company to post collateral, letters of credit, cash or other forms of security as financial assurance of the Company’s performance under certain contractual arrangements with marketing counterparties, facility construction contracts, and pipeline and midstream service providers. Additionally, certain of these arrangements contain financial assurance language that may, under certain circumstances, permit the Company’s counterparties to request additional collateral.

In connection with certain over-the-counter derivatives contracts and other trading agreements, the Company could be required to provide additional collateral or to terminate transactions with certain counterparties based on its credit rating. The occurrence of any of the foregoing could adversely affect the Company’s ability to execute portions of its business strategy, including hedging, and could have a material adverse effect on its liquidity and capital position.

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

As at December 31, 2017, the Company had total long-term debt of $4,197 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.

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

The Company’s business is subject to the operating risks normally associated with the exploration for, development of and production of natural gas, oil and NGLs and the operation of midstream facilities. These risks include blowouts, explosions, fire, gaseous leaks, migration of harmful substances and liquid spills, loss of well control, surface spills and uncontrolled ground releases of fluids during hydraulic fracturing or other similar activities, and acts of vandalism and terrorism, any of which could cause personal injury, result in damage to, or destruction of, natural gas and oil wells or formations or production facilities and other property, equipment and the environment, as well as interrupt operations.

In addition, all of Encana’s operations will be subject to all of the risks normally incident to the transportation, processing, storing and marketing of natural gas, oil, NGLs and other related products, drilling and completion of natural gas and oil wells, and the operation and development of natural gas and oil properties, including encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of natural gas, oil or well fluids, adverse weather conditions and other natural disasters, spills and migration of hazardous chemicals, pollution and other environmental risks.

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.

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. 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, associated asset retirement obligations, due diligence, favourable market conditions, the assignability of joint venture, partnership or other arrangements and stock exchange, regulatory and third party approvals. These factors may also reduce the proceeds or value to Encana.

The Company may also retain certain liabilities for certain matters in a sale transaction. The magnitude of any such retained liabilities or indemnification obligations may be difficult to quantify at the time of the transaction and could ultimately be material. Further, certain third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after the sale of certain assets, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the purchaser of the assets fails to perform its obligations.

The decision to pay dividends and the amount of such dividends is subject to the discretion of the Board of Directors based on numerous factors and may vary from time to time.

Although the Company currently intends to pay quarterly cash dividends to its shareholders, these cash dividends may vary from time to time and could be increased, reduced or suspended. The amount of cash available to the Company to pay dividends, if any, can vary significantly from period to period for a number of reasons, including, among other things: Encana’s operational and financial performance; fluctuations in the costs to produce natural gas, oil and NGLs; the amount of cash required or retained for debt service or repayment; amounts required to fund capital expenditures and working capital

requirements; access to equity markets; foreign currency exchange rates and interest rates; and the risk factors set forth in this Annual Report on Form 10-K.

The decision whether or not to pay dividends and the amount of any such dividends are subject to the discretion of the Board of Directors, which regularly evaluates the Company’s proposed dividend payments and the solvency test requirements of the CBCA. In addition, the level of dividends per common share will be affected by the number of outstanding common shares and other securities that may be entitled to receive cash dividends or other payments. Dividends may be increased, reduced or suspended depending on the Company’s operational success and the performance of its assets. The market value of the common shares may deteriorate if the Company is unable to meet dividend expectations in the future, and that deterioration may be material.

Changes to existing regulations related to income tax laws, royalty regimes, environmental laws or other regulations could adversely affect the Company’s business, financial position, cash flows or results of operations.

Income tax laws, including recent U.S. tax reform and potential U.S. Treasury Department regulations and guidance, royalty regimes, environmental laws or other laws and regulations, and free trade agreements, including NAFTA, may change or be interpreted in a manner that adversely affects the Company or its securityholders. Tax authorities having jurisdiction over the Company or its shareholders could change their administrative practices, or may disagree with the manner in which the Company calculates its tax liabilities or structures its arrangements, to the detriment of the Company or its securityholders. Changes to existing laws and regulations or the adoption of new laws and regulations could also increase the Company’s cost of compliance and adversely affect the Company’s business, financial position, cash flows or results of operations.

Encana does not operate all of its properties and assets and has limited control over factors that could adversely affect the Company’s financial performance.

Other companies operate a portion of the assets in which Encana has ownership interests. Encana may have limited ability to exercise influence over operation of these assets or their associated costs. Encana’s dependence on the operator and other working interest owners for these properties and assets, and its limited ability to influence operations and associated costs, could materially adversely affect the Company’s financial performance. The success and timing of Encana’s activities on assets operated by others therefore will depend upon factors that are outside of the Company’s control, including timing and amount of capital expenditures, timing and amount of operating and maintenance expenditures, the operator’s expertise and financial resources, approval of other participants, selection of technology and risk management practices.

Fluctuations in exchange rates could affect expenses or result in realized and unrealized losses.

Worldwide prices for natural gas and oil are set in U.S. dollars. Although Encana’s financial results are consolidated in Canadian dollars, the Company reports its financial results in U.S. dollars. As Encana operates in both Canada and the U.S., many of the Company’s expenses are incurred outside of the U.S. and are denominated in Canadian dollars. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could impact the Company’s revenue and expenses and have an adverse effect on the Company’s financial performance and condition.

In addition, the Company has U.S. dollar denominated long-term debt. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could result in realized and unrealized losses on U.S. dollar denominated long-term debt.

The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material adverse effect on us.

Encana is exposed to the risks associated with counterparty performance including credit risk and performance risk. Encana may experience material financial losses in the event of customer payment default for commodity sales and financial derivative transactions. Encana’s liquidity may also be impacted if any lender under the Company’s existing credit facilities is unable to fund its commitment. Performance risk can impact Encana’s operations by the non-delivery of contracted products or services by counterparties, which could impact project timelines or operational efficiency.

The Company is subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in the Company’s favour.

Encana may be subject to claims, litigation, administrative proceedings and regulatory actions. The outcome of these matters may be difficult to assess or quantify, and there cannot be any assurance that such matters will be resolved in the Company’s favour. If Encana is unable to resolve such matters favourably, the Company or its directors, officers or employees may become involved in legal proceedings that could result in an onerous or unfavourable decision, including fines, sanctions, monetary damages or the inability to engage in certain operations or transactions. The defence of such matters may also be costly and time consuming, and could divert the attention of management and key personnel from the Company’s operations. Encana may also be subject to adverse publicity associated with such matters, regardless of whether such allegations are valid or whether the Company is ultimately found liable. As a result, such matters could have a material adverse effect on the Company’s reputation, financial position, results of operations or liquidity. See Item 3 of this Annual Report on Form 10-K.

Encana relies on certain key personnel, and if the Company is unable to attract and retain key personnel necessary for its business, Encana’s operations may be negatively impacted.

The Company relies on certain key personnel for the development of its business. The experience, knowledge and contributions of the Company’s existing management team and directors to the immediate and near-term operations and direction of the Company are likely to continue to be of central importance for the foreseeable future. As such, the unexpected loss of services from or retirement of such key personnel could have a material adverse effect on the Company. In addition, the competition for qualified personnel in the oil and gas industry means there can be no assurance that the Company will be able to attract and retain such personnel with the required specialized skills necessary for its business.

Encana has certain indemnification obligations to certain counterparties that could have a material adverse effect on Encana.

Encana has agreed to indemnify or be indemnified by numerous counterparties for certain liabilities and obligations associated with businesses or assets retained or transferred by the Company. Specifically, in relation to a corporate reorganization to split into two independent publicly traded energy companies, Encana and Cenovus Energy Inc. (“Cenovus”) have each agreed to indemnify the other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity, the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the business and assets transferred to Cenovus. Encana also has indemnification obligations under certain acquisition and divestiture activities it has undertaken.

Encana cannot determine whether it will be required to indemnify certain counterparties for any substantial obligations. Encana also cannot be assured that, if a counterparty is required to indemnify Encana and its affiliates for any substantial obligations, such counterparties will be able to satisfy such obligations. Any indemnification claims against Encana pursuant to the provisions of the transaction agreements could have a material adverse effect on Encana.

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 24 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.

PART II

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

On February 15, 2018, the Company announced plans to spend up to US$400 million to purchase for cancellation up to 35,000,000 common shares through a NCIB, subject to and following TSX approval. On February 26, 2018, the Company announced that the TSX accepted its notice of intention to commence the NCIB beginning February 28, 2018 and ending February 27, 2019, whereby purchases will be made on the open market through the facilities of the TSX, NYSE and/or alternative trading systems at the market price at the time of acquisition, as well as by other means as may be permitted by stock exchange rules and securities laws, including by private agreements. The Company plans to fund the NCIB with cash on hand and has not purchased any of its common shares pursuant to a NCIB within the 12 months prior to such announcements.

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)
*2017*
Three months ended:
December 31, 2017		16.93		13.03		13.52		10.16
September 30, 2017		14.97		10.54		12.01		8.17
June 30, 2017		16.40		10.64		12.25		8.02
March 31, 2017		18.13		13.61		13.84		10.07

*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

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 16, 2018, there were approximately 973 million common shares outstanding held by 24,696 shareholders of record, and no Class A Preferred Shares outstanding.

Dividend Information

In 2017, Encana paid a quarterly dividend of US$0.015 per share (US$0.06 per share annually). In 2016, Encana paid a quarterly dividend of US$0.015 per share (US$0.06 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.

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 2018 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.

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; Obsidian Energy 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, 2012 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	2012		2013		2014		2015		2016		2017
Encana	$	100.00	$	95.00	$	74.00	$	28.00	$	65.00	$	75.00
Peer Group		100.00		129.00		99.00		59.00		87.00		79.00
S&P 500		100.00		132.00		150.00		153.00		171.00		208.00
S&P/TSX Composite Index		100.00		113.00		125.00		115.00		139.00		151.00

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, 2017, which has been derived from the Company’s audited Consolidated Financial Statements. The financial information below should be read in conjunction with Item 7 and Item 8 of this Annual Report on Form 10-K.


Year Ended December 31 (US$ millions, unless otherwise specified)	2017			2016			2015			2014			2013

Statement of Earnings Data

Revenues		4,443			2,918			4,422			8,019			5,858

Impairments		-			1,396			6,473			-			21

Operating Income (Loss)		1,068			(1,881	)		(6,301	)		2,331			870

Gain (Loss) on Divestitures, Net		404			390			14			3,426			7

Net Earnings (Loss) Attributable to Common Shareholders		827			(944	)		(5,165	)		3,392			236

Per Share Data

Net Earnings (Loss) per Common Share Basic & Diluted		0.85			(1.07	)		(6.28	)		4.58			0.32

Dividends Declared per Common Share		0.06			0.06			0.28			0.28			0.67

Weighted Average Common Shares Outstanding Basic & Diluted (millions)		973.1			882.6			822.1			741.0			737.7

Balance Sheet Data

Cash and Cash Equivalents		719			834			271			338			2,566

Total Assets		15,267			14,653			15,614			24,492			17,599

Capital Lease Obligations and The Bow Office Building		1,639			1,570			1,591			1,959			2,175

Long-Term Debt, Including Current Portion		4,197			4,198			5,333			7,301			7,078

Total Shareholders’ Equity		6,728			6,126			6,167			9,685			5,147

Statement of Cash Flow Data

Cash From (Used In) Operating Activities		1,050			625			1,681			2,667			2,289

Non-GAAP Cash Flow ⁽¹⁾		1,343			838			1,430			2,934			2,581

Capital Expenditures		1,796			1,132			2,232			2,526			2,712

Net Acquisitions & (Divestitures)		(682	)		(1,052	)		(1,838	)		(1,329	)		(521	)

Foreign Exchange Rates (US$ per C$1)

Average		0.771			0.755			0.782			0.905			0.971

Period End		0.797			0.745			0.723			0.862			0.940

Production Volumes

Oil (Mbbls/d)		76.3			73.7			87.0			49.4			25.8

Total NGLs (Mbbls/d) ⁽²⁾		52.8			48.4			46.4			37.4			28.1

Total Oil & NGLs (Mbbls/d)		129.1			122.1			133.4			86.8			53.9

Natural Gas (MMcf/d)		1,104			1,383			1,635			2,350			2,777

Total Production (MBOE/d)		313.2			352.7			405.9			478.5			516.7

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

Oil ($/bbl)		49.76			48.68			49.68			86.03			88.19

Total NGLs ($/bbl)⁽²⁾		34.72			23.90			21.66			48.09			48.95

Oil & NGLs ($/bbl)		43.61			38.85			39.93			69.70			67.75

Natural Gas ($/Mcf)		2.42			2.10			3.89			4.59			4.09

Total ($/BOE)		26.51			21.69			28.81			35.21			29.05

⁽¹⁾

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.

⁽²⁾	Includes plant condensate.

Supplemental Quarterly Financial Information (Unaudited)

See Note 26 of Encana’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

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, 2017 (“Consolidated Financial Statements”), which are included in Item 8 of this Annual Report on Form 10-K. Common industry terms and abbreviations are used throughout this MD&A and are defined in the Definitions, Conversions and Conventions sections of this Annual Report on Form 10-K. This MD&A includes the following sections:

Executive Overview

Results of Operations

Liquidity and Capital Resources

Accounting Policies and Estimates

Non-GAAP Measures

Executive Overview

Strategy

By executing on its strategy as outlined in Items 1 and 2 of this Annual Report on Form 10-K, Encana focuses on quality 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 of oil, NGL and natural gas producing plays 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.

In executing its strategy, Encana focuses on its core values of One, Agile and Driven, which guide the organization to be flexible, responsive, determined and motivated with a commitment to excellence and a passion to succeed as a unified team.

In evaluating its operations, the Company reviews performance-based measures such as Non-GAAP Cash Flow and Non-GAAP Cash Flow 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.

Highlights

During 2017, Encana met or exceeded substantially all of the targets set in its full year 2017 guidance by successfully executing the Company’s 2017 capital plan, maintaining operational efficiencies achieved in 2016 and seeking new ways to reduce costs. Higher benchmark prices during 2017 compared to 2016 contributed to increases in Encana’s average realized oil, NGLs and natural gas prices of 27 percent, 46 percent and 23 percent, respectively, resulting in higher revenues.

Significant Developments

Closed the sale of the Company’s Piceance natural gas assets in northwestern Colorado to Caerus Oil and Gas LLC for proceeds of approximately $605 million, after closing and other adjustments. In conjunction with the sale, Encana also reduced its midstream commitments by approximately $430 million (undiscounted).

Commenced processing of production volumes in support of the Company’s liquids growth plans in Montney at the Tower, Saturn and Sunrise processing plants under a midstream agreement with Veresen Midstream Limited Partnership.

Financial Results

Reported net earnings of $827 million, including before-tax amounts for net gains on risk management in revenues of $482 million, gain on divestitures of $404 million and foreign exchange gain of $279 million, as well as deferred tax expense of $666 million.

Generated cash from operating activities of $1,050 million, Non-GAAP Cash Flow of $1,343 million and Non-GAAP Cash Flow Margin of $11.75 per BOE.

Recovered current taxes of approximately $63 million and interest of $17 million, as well as received interest income of $33 million primarily resulting from the successful resolution of certain tax items previously assessed.

Paid dividends of $0.06 per common share.

Held cash and cash equivalents of $719 million and had available credit facilities of $4.5 billion for total liquidity of $5.2 billion at year end.

Capital Investment

Reported total capital spending of $1,796 million which was within the full year 2017 guidance range of $1.6 billion to $1.8 billion.

Directed $1,729 million, or 96 percent, of total capital spending to the Core Assets, of which 58 percent was directed to Permian.

Focused on highly efficient capital activity and short-cycle high margin projects providing flexibility to respond to fluctuations in commodity prices.

Production

Produced average oil and NGL volumes of 129.1 Mbbls/d which accounted for 41 percent of total production volumes and were within the full year 2017 guidance range of 127.0 Mbbls/d to 132.0 Mbbls/d. Average oil and plant condensate production volumes of 102.6 Mbbls/d were 79 percent of total liquids production volumes.

Produced average natural gas volumes of 1,104 MMcf/d which accounted for 59 percent of total production volumes and were within the full year 2017 guidance range of 1,075 MMcf/d to 1,125 MMcf/d.

Reported Core Assets production of 260.7 MBOE/d, or 83 percent of total production volumes, and delivered production growth of approximately 31 percent from the fourth quarter of 2016 to the fourth quarter of 2017 surpassing the top end of the full year 2017 guidance range of 25 to 30 percent.

Operating Expenses

Continued to benefit from operational efficiencies achieved in 2016, which contributed to further cost savings improvements in 2017.

Achieved all targets set in the full year 2017 guidance range for transportation and processing expense, and upstream operating expense and administrative expense excluding long-term incentive costs.

Reduced transportation and processing expense in 2017 by $56 million, or six percent, and reduced operating expense, excluding long-term incentive costs, by $78 million, or 14 percent, compared to 2016.

Reduced administrative expense by $11 million, or six percent, excluding the impact of long-term incentive costs and restructuring charges compared to 2016.

2018 Outlook

Industry Outlook

The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices during 2018 are expected to reflect global supply and demand dynamics as well as the geopolitical environment. At a meeting in November 2017, OPEC and certain non-OPEC countries agreed to further extend an agreement to voluntarily cut crude oil production through the end of 2018. The agreement, which was implemented in January 2017, and recent drawdowns of oil storage inventory levels, were generally supportive of oil prices in 2017; however, production growth in other countries continues to partially offset the expected benefit of the OPEC agreement. OPEC is scheduled to meet again in June 2018 to review production levels and a decision to discontinue or reduce the production cuts could negatively impact oil prices in 2018.

Natural gas prices in 2018 will be affected by the timing of supply and demand growth. Potential for improvement in U.S. natural gas prices is limited due to substantial production increases in Northeast U.S. and associated gas production in the Permian Basin, offsetting the positive impact of colder winter temperatures. Natural gas prices in Canada have seen significant negative price pressure as supply reached multi-year highs, surpassing regional demand and stressing effective pipeline capacity. Stronger condensate prices may also lend support to activity levels resulting in additional downward pressure on natural gas prices.

Company Outlook

Encana has positioned itself to be flexible and to continue to achieve strong returns from the Core Assets through this evolving price cycle. A portion of the Company’s oil, NGL and natural gas production is sold at prevailing market prices, which fluctuate as a result of factors that are outside of Encana’s control. The Company enters into derivative financial instruments which mitigate price volatility and help sustain revenues during periods of lower prices. As at February 12, 2018, the Company has hedged approximately 104,000 bbls/d of expected oil and condensate production and 790 MMcf/d of expected natural gas production for the remainder of 2018 using a variety of structures at average prices of $54.48 per bbl and $3.03 per Mcf, respectively.

Markets for crude oil and natural gas are exposed to different price risks. While the market price for crude oil tends to move in the same direction as the global market, natural gas may vary between geographic regions depending on local supply and demand conditions. Encana has proactively utilized transportation contracts to diversify the Company’s downstream markets and reduce significant exposure to any given market. Through a combination of derivative financial instruments and transportation capacity, Encana has removed the majority of its exposure to AECO pricing in 2018.

Capital Investment

Total anticipated 2018 capital investment of approximately $1.8 billion to $1.9 billion is expected to be primarily funded from 2018 cash generated from operating activities. Encana plans to focus the majority of its capital investment on its Core Assets with approximately 70 percent directed to Permian and Montney. Capital investment in Permian is expected to be focused on optimizing the cube development approach to maximize returns and recovery. Capital investment in Montney is expected to be allocated to both Cutbank Ridge and Pipestone with a focus on growing condensate. Access to liquids handling infrastructure planned for completion in the second half of 2018 is expected to support liquids growth in Montney.

Encana continually strives to improve well performance by lowering drilling and completion costs through innovative techniques. Encana’s large-scale cube development model utilizes multi-well pads and advanced completion designs to access stacked pay resource to maximize returns and resource recovery from its reservoirs. The impact of Encana’s disciplined capital program and continuous innovation create flexibility and opportunity to grow cash flows and production volumes going forward.

Production

As part of the Company’s long-term growth strategy, Encana has significantly shifted its production mix to a more balanced portfolio in the recent years, thereby reducing exposure to market volatility. In 2018, Encana expects to continue to focus on growing condensate and expects liquids production volumes of 165.0 Mbbls/d to 175.0 Mbbls/d and natural gas production volumes of 1,150 MMcf/d to 1,250 MMcf/d. Liquids production is expected to be approximately 46 percent of total production in 2018. Liquids growth from Montney will be supported by the Tower, Saturn and Sunrise processing plants completed in 2017, as well as two facilities expected to be completed in the second half of 2018. Core Asset production will account for the majority of total production volumes with significant oil and condensate growth in the second half of the year. Growing production in the Core Assets is expected to increase cash flows and deliver competitive returns.

Operating Expenses

Efficiency improvements and lower service costs are expected to be maintained through the support of the Company’s culture of innovation and its focus on continuous improvement in operational execution. As activity in the industry begins to accelerate, Encana expects to continue pursuing innovative ways to reduce upstream operating and administrative expenses. Encana expects upstream operating expense of $3.00 per BOE to $3.30 per BOE and transportation and processing expense of $7.40 per BOE to $7.75 per BOE. Transportation and processing expense includes costs relating to the diversification of the Company’s downstream markets that are expected to increase overall margins through higher prices. Administrative expense is expected to be between $1.25 per BOE to $1.50 per BOE. Guidance for upstream operating expense and administrative expense excludes long-term incentive costs.

Service costs are expected to increase with higher activity in the oil and gas industry and the recovery of commodity prices. Encana continues to offset any inflationary pressures with efficiency improvements and effective supply chain management, including favorable price negotiations.

Further information on Encana’s 2018 Corporate Guidance can be accessed on the Company’s website at www.encana.com.

Results of Operations

Selected Financial Information


($ millions)	2017	2016	2015

Product Revenues	$ 2,999	$ 2,443	$ 3,350

Gains (Losses) on Risk Management, net	482	(275)	592

Market Optimization	863	647	368

Other	99	103	112

Total Revenues	4,443	2,918	4,422

Total Operating Expenses ⁽¹⁾	3,375	4,799	10,723

Operating Income (Loss)	1,068	(1,881)	(6,301)

Total Other (Income) Expenses	(362)	(261)	1,709

Net Earnings (Loss) Before Income Tax	1,430	(1,620)	(8,010)

Net Earnings (Loss)	$ 827	$ (944)	$ (5,165)

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

Revenues

Encana’s revenues are substantially derived from sales of oil, NGL and natural gas 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 fluctuate due to factors beyond the Company’s control, such as supply and demand, seasonality and geopolitical and economic factors. Canadian Operations realized prices are closely linked to the Edmonton Condensate and AECO 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 WTI and NYMEX 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)		2017		2016		2015

Oil & NGLs

WTI ($/bbl)	$	50.95	$	43.32	$	48.80

Edmonton Condensate (C$/bbl)		66.90		56.18		60.33

Natural Gas

NYMEX ($/MMBtu)	$	3.11	$	2.46	$	2.66

AECO (C$/Mcf)		2.43		2.09		2.77

Algonquin City Gate ($/MMBtu)		3.68		3.10		4.74

Production Volumes and Realized Prices


	Production Volumes⁽¹⁾						Realized Prices⁽²⁾
	2017		2016		2015		2017		2016		2015

Oil (Mbbls/d, $/bbl)

Canadian Operations		0.4		2.0		5.6	$	42.33	$	36.32	$	43.90

USA Operations		75.9		71.7		81.4		49.14		38.67		43.31

Total		76.3		73.7		87.0		49.10		38.61		43.35

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

Canadian Operations		23.1		17.6		13.9		50.57		40.97		43.26

USA Operations		3.2		2.7		2.9		40.64		32.48		37.39

Total		26.3		20.3		16.8		49.35		39.84		42.26

NGLs – Other (Mbbls/d, $/bbl)

Canadian Operations		6.0		7.6		8.9		25.19		12.13		7.13

USA Operations		20.5		20.5		20.7		19.42		12.53		11.20

Total		26.5		28.1		29.6		20.72		12.42		9.98

Total NGLs (Mbbls/d, $/bbl)

Canadian Operations		29.1		25.2		22.8		45.35		32.32		29.21

USA Operations		23.7		23.2		23.6		22.30		14.86		14.37

Total		52.8		48.4		46.4		34.98		23.94		21.66

Total Oil & NGLs (Mbbls/d, $/bbl)

Canadian Operations		29.5		27.2		28.4		45.30		32.61		32.10

USA Operations		99.6		94.9		105.0		42.74		32.84		36.80

Total		129.1		122.1		133.4		43.33		32.79		35.80

Natural Gas (MMcf/d, $/Mcf)

Canadian Operations		838		966		971		2.16		1.77		2.75

USA Operations		266		417		664		3.03		2.29		2.60

Total		1,104		1,383		1,635		2.37		1.93		2.69

Total Production (MBOE/d, $/BOE)

Canadian Operations		169.1		188.2		190.2		18.61		13.82		18.84

USA Operations		144.1		164.5		215.7		35.16		24.78		25.93

Total		313.2		352.7		405.9		26.22		18.93		22.61

Production Mix (%)

Oil & Plant Condensate		33		27		26

NGLs – Other		8		8		7

Total Oil & NGLs		41		35		33

Natural Gas		59		65		67

Core Asset Production

Oil (Mbbls/d)		72.6		64.1		66.5

NGLs – Plant Condensate (Mbbls/d)		25.8		19.2		15.1

NGLs – Other (Mbbls/d)		24.7		22.9		21.3

Total NGLs (Mbbls/d)		50.5		42.1		36.4

Total Oil & NGLs (Mbbls/d)		123.1		106.2		102.9

Natural Gas (MMcf/d)		826		887		838

Total Production (MBOE/d)		260.7		254.2		242.6

% of Total Encana Production		83		72		60

(1)	Average daily.

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

Product Revenues


($ millions)	Oil			NGLs ⁽¹⁾		Natural Gas			Total

2015 Product Revenues	$	1,378		$	367	$	1,605		$	3,350

Increase (decrease) due to:

Sales prices		(128	)		33		(369	)		(464)

Production volumes		(209	)		24		(258	)		(443)

2016 Product Revenues	$	1,041		$	424	$	978		$	2,443

Increase (decrease) due to:

Sales prices		290			203		201			694

Production volumes		36			47		(221	)		(138)

2017 Product Revenues	$	1,367		$	674	$	958		$	2,999

(1)	Includes plant condensate.

Oil Revenues

2017 versus 2016

Oil revenues increased $326 million compared to 2016 primarily due to:

Higher average realized oil prices of $10.49 per bbl, or 27 percent, increased revenues by $290 million. The increase reflected a higher WTI benchmark price which was up 18 percent. The increase was also due to higher utilization of pipelines to transport oil to more favourable markets to receive a higher realized price, as well as improved regional pricing in the USA Operations; and

Higher average oil production volumes of 2.6 Mbbls/d increased revenues by $36 million. Higher volumes were primarily due to a successful drilling program in Permian (11.6 Mbbls/d), partially offset by the sales of the DJ Basin and Gordondale assets in the third quarter of 2016 and the Tuscaloosa Marine Shale assets in the second quarter of 2017 (5.3 Mbbls/d), natural declines in the USA Other Upstream Operations (1.5 Mbbls/d) and Eagle Ford (1.3 Mbbls/d) and production constraints resulting from Hurricane Harvey in Eagle Ford and Permian during the third quarter of 2017 (0.5 Mbbls/d).

2016 versus 2015

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

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 Condensate benchmark prices which were down 11 percent and seven percent, respectively; and

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 and Gordondale assets in the third quarter of 2016 (3.1 Mbbls/d), partially offset by a successful drilling program in Permian (5.8 Mbbls/d).

NGL Revenues

2017 versus 2016

NGL revenues increased $250 million compared to 2016 primarily due to:

Higher average realized NGL prices of $11.04 per bbl, or 46 percent, increased revenues by $203 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 18 percent and 19 percent, respectively. The increase was also due to a shift in the NGL production mix to higher value condensate compared to 2016; and

Higher average NGL production volumes of 4.4 Mbbls/d increased revenues by $47 million. Higher volumes were primarily due to successful drilling programs in the Core Assets (12.3 Mbbls/d), partially offset by asset sales (7.0 Mbbls/d) which mainly include the Gordondale and DJ Basin assets in the third quarter of 2016, and natural declines in Other Upstream Operations (0.6 Mbbls/d).

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 and DJ Basin assets in the third quarter of 2016 (4.5 Mbbls/d) and natural declines in the USA Other Upstream Operations (1.1 Mbbls/d).

Natural Gas Revenues

2017 versus 2016

Natural gas revenues decreased $20 million compared to 2016 primarily due to:

Lower average natural gas production volumes of 279 MMcf/d decreased revenues by $221 million. Lower volumes were primarily due to asset sales (198 MMcf/d) which mainly include the Piceance natural gas assets in the third quarter of 2017 and the Gordondale and DJ Basin assets in the third quarter of 2016, natural declines in Other Upstream Operations (77 MMcf/d) and increased downtime resulting from scheduled third-party plant maintenance in Montney (19 MMcf/d), partially offset by a successful drilling program in Permian (17 MMcf/d);

partially offset by:

Higher average realized natural gas prices of $0.44 per Mcf, or 23 percent, increased revenues by $201 million. The increase reflected higher NYMEX, AECO and Algonquin City Gate benchmark prices which were up 26 percent, 16 percent and 19 percent, respectively. The increase was also due to the diversification of the Company’s downstream markets to capture a higher realized price.

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 eight 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 sale of the Haynesville natural gas assets in the fourth quarter of 2015 (152 MMcf/d), the sales of the Gordondale and DJ Basin assets in the third quarter of 2016 (53 MMcf/d) and natural declines in Other Upstream Operations (86 MMcf/d), partially offset by successful drilling programs in Montney and Duvernay (66 MMcf/d).

Gains (Losses) on Risk Management, Net

As a means of managing commodity price volatility, Encana enters into commodity derivative financial instruments on a portion of its expected oil, NGL and natural gas production volumes. The Company’s commodity price mitigation program reduces volatility and helps sustain revenues during periods of lower prices. Further information on the Company’s commodity price positions as at December 31, 2017 can be found in Note 22 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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


	$ millions									Per-Unit
	2017			2016			2015			2017			2016			2015

Realized Gains (Losses) on Risk Management

Commodity Price

Oil ($/bbl)	$	18		$	271		$	201		$	0.66		$	10.07		$	6.33

NGLs ($/bbl) ⁽¹⁾		(5	)		-			-			(0.26	)		(0.04	)		-

Natural Gas ($/Mcf)		20			85			718			0.05			0.17			1.20

Other ⁽²⁾		7			5			(2	)		-			-			-

Total ($/BOE)		40			361			917		$	0.29		$	2.76		$	6.20

Unrealized Gains (Losses) on Risk Management		442			(636	)		(325	)

Total Gains (Losses) on Risk Management, Net	$	482		$	(275	)	$	592

(1)	Includes plant condensate.

(2)	Other primarily 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.

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.

($ millions)

2017

2016

2015

Market Optimization

863

647

368

2017 versus 2016

Market Optimization revenues increased $216 million compared to 2016 primarily due to:

Higher commodity prices ($166 million) and higher sales of third-party purchased volumes used for optimization activities ($50 million).

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).

Other Revenues

Other revenues primarily includes amounts related to the sublease of office space in The Bow office building 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 13 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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
	2017		2016		2015		2017		2016		2015

Canadian Operations	$	20	$	23	$	28	$	0.33	$	0.33	$	0.41

USA Operations		92		76		116	$	1.74	$	1.27	$	1.47

Total	$	112	$	99	$	144	$	0.98	$	0.77	$	0.97

2017 versus 2016

Production, mineral and other taxes increased $13 million compared to 2016 primarily due to:

Higher commodity prices in the USA Operations and higher oil and NGL production volumes in Permian ($31 million);

partially offset by:

The sales of the DJ Basin and Gordondale assets in the third quarter of 2016 and the Piceance natural gas assets in the third quarter of 2017 ($10 million) and the recovery of certain production taxes in the USA Operations ($8 million).

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).

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
	2017		2016			2015		2017		2016		2015

Canadian Operations	$	578	$	576		$	654	$	9.35	$	8.35	$	9.42

USA Operations		164		260			580	$	3.12	$	4.33	$	7.37

Upstream Transportation and Processing		742		836			1,234	$	6.49	$	6.48	$	8.33

Market Optimization		103		87			12

Corporate and Other		-		(22	)		6

Total	$	845	$	901		$	1,252

2017 versus 2016

Transportation and processing expense decreased $56 million compared to 2016 primarily due to:

Asset sales ($107 million) which mainly include the DJ Basin and Gordondale assets in the third quarter of 2016 and the Piceance natural gas assets in the third quarter of 2017, the renegotiation and expiration of certain transportation contracts ($32 million), lower natural gas volumes and lower gas gathering and processing fees in Montney and Other Upstream Operations ($9 million) and lower activity in Duvernay ($4 million);

partially offset by:

Increased downstream processing and transportation costs primarily in Montney and Duvernay due to Encana’s focus on liquids rich wells in the plays and costs relating to the diversification of the Company’s downstream markets ($40 million), higher volumes and prices in Permian ($25 million), unrealized risk management gains on power financial derivative contracts in 2016 ($22 million) and the higher U.S./Canadian dollar exchange rate ($11 million).

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).

Operating

Operating expense includes costs paid by Encana, net of amounts capitalized, to operate oil and gas properties in which the Company has a working interest. These costs primarily include labour, service contract fees, chemicals and fuel.


	$ millions						$/BOE
	2017		2016		2015		2017		2016		2015

Canadian Operations	$	122	$	152	$	152	$	1.92	$	2.16	$	2.17

USA Operations		331		394		519	$	6.18	$	6.44	$	6.55

Upstream Operating Expense ⁽¹⁾		453		546		671	$	3.88	$	4.16	$	4.50

Market Optimization		35		35		33

Corporate and Other		18		17		19

Total	$	506	$	598	$	723

(1)	2017 Upstream Operating Expense per BOE includes long-term incentive costs of $0.19/BOE (2016 - costs of $0.29/BOE; 2015 - a recovery of $0.04/BOE).

2017 versus 2016

Operating expense decreased $92 million compared to 2016 primarily due to:

Asset sales ($66 million) which mainly include the DJ Basin and Gordondale assets in the third quarter of 2016, the Piceance natural gas assets in the third quarter of 2017 and the Tuscaloosa Marine Shale assets in the second quarter of 2017, lower salaries and benefits and long-term incentive costs due to higher headcount dedicated to the capital program and a smaller increase in Encana’s share price during 2017 compared to 2016 ($47 million) and cost-saving initiatives ($24 million);

partially offset by:

Higher activity in Permian and Montney ($39 million) and the higher U.S./Canadian dollar exchange rate ($4 million).

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 19 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Purchased Product

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

($ millions)

2017

2016

2015

Market Optimization

788

586

323

2017 versus 2016

Purchased product expense increased $202 million compared to 2016 primarily due to:

Higher commodity prices ($152 million) and higher third-party volumes purchased for optimization activities ($50 million).

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).

Depreciation, Depletion & Amortization

Proved properties within each country cost centre are depleted using the unit-of-production method based on proved reserves as discussed in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates as well as fluctuations in 12-month average trailing prices which affect proved reserves volumes. Additional information can be found in the Critical Accounting Estimates section of this MD&A under Upstream Assets and Reserve Estimates. Corporate assets are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets.


	$ millions						$/BOE
	2017		2016		2015		2017		2016		2015

Canadian Operations	$	236	$	260	$	305	$	3.82	$	3.77	$	4.39

USA Operations		530		523		1,088	$	10.09	$	8.68	$	13.66

Upstream DD&A		766		783		1,393	$	6.70	$	6.06	$	9.31

Market Optimization		1		-		-

Corporate and Other		66		76		95

Total	$	833	$	859	$	1,488

2017 versus 2016

DD&A decreased $26 million compared to 2016 primarily due to:

Lower production volumes ($85 million) and lower straight-line depreciation on corporate assets ($12 million), partially offset by higher depletion rates primarily in the USA Operations ($63 million) and the higher U.S./Canadian dollar exchange rate ($5 million).

The depletion rate increased $0.64 per BOE compared to 2016 primarily due to:

Lower reserve volumes from the sale of the Piceance natural gas assets in the third quarter of 2017, partially offset by ceiling test impairments recognized in the first six months of 2016 in the Canadian and USA Operations, and the sale of the DJ Basin assets in the third quarter of 2016. The sale of the Piceance natural gas assets resulted in the recognition of a gain on divestiture, whereas proceeds from the sale of the DJ Basin assets were deducted from the U.S. full cost pool. Additional information on the divestitures can be found in Note 3 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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.

Impairments

Under full cost accounting, the carrying amount of Encana’s oil and natural gas properties within each country cost centre is subject to a ceiling test at the end of each quarter. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum of the estimated after-tax future net cash flows from proved reserves as calculated under SEC requirements using the 12-month average trailing prices and discounted at 10 percent.


($ millions)	2017	2016		2015

Canadian Operations	$ -	$	493	$	-

USA Operations	-		903		6,473

Total	$ -	$	1,396	$	6,473

The Company did not recognize any ceiling test impairments for 2017. The ceiling test impairments in 2016 and 2015 were primarily due to the decline in the 12-month average trailing prices, which reduced the Canadian and USA Operations proved reserves volumes and values as calculated under SEC requirements.

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.


	Oil & NGLs				Natural Gas
	WTI ($/bbl)		Edmonton Condensate⁽²⁾ (C$/bbl)		Henry Hub ($/MMBtu)		AECO (C$/MMBtu)

12-Month Average Trailing Reserves Pricing ⁽¹⁾

2017		51.34		67.65		2.98		2.32

2016		42.75		55.39		2.49		2.17

2015		50.28		61.94		2.58		2.69

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

(2)	Edmonton Condensate benchmark price has replaced the previously disclosed Edmonton Light Sweet benchmark price.

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 oil and natural gas 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 liquids and natural gas 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 and long-term incentive costs.


	2017		2016		2015

Administrative ($ millions)	$	254	$	309	$	275

Administrative ($/BOE) ⁽¹⁾	$	2.22	$	2.40	$	1.86

(1)	2017 administrative expense per BOE includes long-term incentive costs of $0.67/BOE. 2016 administrative expense per BOE includes long-term incentive costs and restructuring costs of $0.93/BOE (2015 - $0.36/BOE).

2017 versus 2016

Administrative expense in 2017 decreased $55 million from 2016 primarily due to lower restructuring costs ($34 million), lower third party payments relating to previously divested assets ($11 million) as well as lower long-term incentive costs resulting from a smaller increase in Encana’s share price during 2017 compared to 2016 ($10 million).

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).

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. Further information on restructuring costs can be found in Note 18 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Other (Income) Expenses


($ millions)	2017			2016			2015

Interest	$	363		$	397		$	614

Foreign exchange (gain) loss, net		(279	)		(210	)		1,082

(Gain) loss on divestitures, net		(404	)		(390	)		(14)

Other (gains) losses, net		(42	)		(58	)		27

Total Other (Income) Expenses	$	(362	)	$	(261	)	$	1,709

Interest

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

2017 versus 2016

Interest expense in 2017 decreased $34 million compared to 2016 primarily due to lower interest on debt ($29 million) resulting from the early retirement of long-term debt in March 2016. Further information on the March 2016 debt retirement can be found in the Liquidity and Capital Resources section of this MD&A.

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.

Foreign Exchange (Gain) Loss, Net

Foreign exchange gains and losses result from the impact of fluctuations in the Canadian to U.S. dollar exchange rate. Further details on changes in foreign exchange gains or losses can be found in Note 5 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Additional information on foreign exchange rates and the effects of foreign exchange rate changes can be found in Items 6 and 7A of this Annual Report on Form 10-K.

2017 versus 2016

In 2017, Encana recorded a higher net foreign exchange gain compared to 2016 ($69 million). The change was primarily due to higher unrealized foreign exchange gains on the translation of U.S. dollar financing debt issued from Canada ($113 million) and unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada compared to losses in 2016 ($48 million), partially offset by foreign exchange losses on the settlement of U.S. dollar financing debt issued from Canada compared to gains in 2016 ($87 million). In 2017, unrealized foreign exchange on the translation of U.S. dollar financing debt issued from Canada included an out-of-period adjustment of $68 million, before tax, in respect of unrealized losses on a foreign-denominated capital lease obligation since December 31, 2013. Further information on the out-of-period adjustment can be found in Note 5 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2016 versus 2015

In 2016, Encana recorded a net foreign exchange gain compared to a net loss in 2015 ($1,292 million). The change was primarily due to unrealized foreign exchange gains on the translation of U.S. dollar financing debt issued from Canada compared to losses in 2015 ($884 million) and foreign exchange gains on the settlement of U.S. dollar financing debt issued from Canada compared to losses in 2015 ($342 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 regarding gains on divestitures can be found in Note 3 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2017

Gain on divestitures in 2017 primarily includes the before tax gain on the sale of the Piceance natural gas assets of approximately $406 million.

2016

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

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.

Other (Gains) Losses, Net

Other (gains) losses, net primarily includes other non-recurring revenues or expenses and may also include items such as interest income on short-term investments, interest received from tax authorities, reclamation charges relating to decommissioned assets and earnings/losses from equity investments.

2017

Other gains in 2017 primarily includes interest received of $33 million resulting from the successful resolution of certain tax items previously assessed by the taxing authorities relating to prior taxation years and interest income on short-term investments of $6 million, partially offset by reclamation charges relating to decommissioned assets of $4 million.

2016

Other gains in 2016 primarily included a gain of $89 million on the early retirement of long-term debt as discussed in the Liquidity and Capital Resources section of this MD&A, partially offset by a one-time third party payment relating to a previously divested asset of $20 million and reclamation charges relating to decommissioned assets of $7 million.

2015

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

Income Tax


($ millions)	2017	2016	2015

Current Income Tax Expense (Recovery)	$ (63)	$ (78)	$ (34)

Deferred Income Tax Expense (Recovery)	666	(598)	(2,811)

Income Tax Expense (Recovery)	$ 603	$ (676)	$ (2,845)

Effective Tax Rate	42.2%	41.7%	35.5%

Income Tax Expense (Recovery)

2017 versus 2016

Total income tax in 2017 was an expense of $603 million compared to a recovery of $676 million in 2016 primarily due to:

Net earnings before income tax in 2017 compared to a net loss before income tax in 2016.

Deferred income tax in 2017 was an expense of $666 million compared to a recovery of $598 million in 2016 due to:

Net earnings (loss) before income tax as discussed above; and

Deferred tax expense in 2017 includes a provisional adjustment of $327 million resulting from the re-measurement of the Company’s tax position due to a reduction of the U.S. federal corporate tax rate from 35 percent to 21 percent under the Tax Cuts and Jobs Act (“U.S. Tax Reform”) as enacted on December 22, 2017. The adjustment of $327 million includes a $26 million valuation allowance re-measurement with respect to U.S. foreign tax credits and U.S. charitable donations. In addition, the deferred tax expense includes a valuation allowance of $28 million against U.S. state losses; and

Deferred tax recovery in 2016 was primarily due to the recognition of non-cash ceiling test impairments.

The current income tax recovery in 2017 was primarily due to the successful resolution of certain tax items previously assessed by the taxing authorities relating to prior taxation years as well as the reclassification of $10 million U.S. alternative minimum tax to a long-term receivable from a deferred tax asset due to U.S. Tax Reform.

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.

Effective Tax Rate

Encana’s annual effective income tax rate is impacted by earnings, income tax related to foreign operations, the effect of legislative changes including U.S. Tax Reform, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. The Company’s effective tax rate was 42.2 percent for 2017, which is higher than the Canadian statutory rate of 27 percent primarily due to U.S. Tax Reform, which increased Encana’s effective tax rate by 22.9 percent. The effective tax rate for 2017 was also impacted by the tax reassessments discussed above as well as the valuation allowance taken against U.S. state losses. 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, including U.S. Tax Reform and potential Treasury Department regulations and guidance, in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. As a result, there are tax matters under review for which the timing of resolution is uncertain. The Company believes that the provision for income taxes is adequate.

Additional information on income taxes can be found in Note 6 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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 or to manage its capital structure as discussed below. At December 31, 2017, $314 million in cash and cash equivalents was held by U.S. subsidiaries. The cash held by U.S. subsidiaries is accessible and may be subject to additional Canadian income taxes and U.S. withholding taxes if repatriated.

The Company’s capital structure consists of total shareholders’ equity plus long-term debt, including the current portion. The Company’s objectives when managing its capital structure are to maintain financial flexibility to preserve Encana’s access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. Encana has a practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, purchasing shares for cancellation through a NCIB, issuing new debt or repaying existing debt.


($ millions, except as indicated)	2017	2016	2015

Cash and Cash Equivalents	$ 719	$ 834	$ 271

Available Credit Facility – Encana ⁽¹⁾	3,000	3,000	2,350

Available Credit Facility – U.S. Subsidiary ⁽¹⁾	1,500	1,500	1,500

Total Liquidity	5,219	5,334	4,121

Long-Term Debt	4,197	4,198	5,333

Total Shareholders’ Equity	6,728	6,126	6,167

Debt to Capitalization (%) ⁽²⁾	38	41	46

Debt to Adjusted Capitalization (%) ⁽³⁾	22	23	28

(1)	Collectively, the “Credit Facilities”.

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

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

Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is a non-GAAP measure defined in the Non-GAAP Measures section of this MD&A, as a proxy for Encana’s financial covenant under the Credit Facilities, which requires debt to adjusted capitalization to be less than 60 percent. The definitions used in the covenant under the Credit Facilities adjust capitalization for cumulative historical ceiling test impairments that were recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Additional information on financial covenants can be found in Note 12 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Sources and Uses of Cash

During 2017, Encana primarily generated cash through operating activities and proceeds from divestitures. The following table summarizes the sources and uses of the Company’s cash and cash equivalents.


($ millions)	Activity Type		2017	2016	2015

Sources of Cash and Cash Equivalents

Cash from operating activities		Operating	$ 1,050	$ 625	$ 1,681

Proceeds from divestitures		Investing	736	1,262	1,908

Issuance of common shares, net of offering costs		Financing	-	1,129	1,088

Other		Investing	77	51	-

			1,863	3,067	4,677

Uses of Cash and Cash Equivalents

Capital expenditures		Investing	1,796	1,132	2,232

Acquisitions		Investing	54	210	70

Net repayment of revolving long-term debt		Financing	-	650	627

Repayment of long-term debt		Financing	-	400	1,302

Dividends on common shares		Financing	57	51	152

Other		Investing/Financing	82	66	332

			1,989	2,509	4,715

Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency			11	5	(29)

Increase (Decrease) in Cash and Cash Equivalents			$ (115)	$ 563	$ (67)

Operating Activities

Cash from operating activities in 2017 was $1,050 million and was primarily impacted by recovering commodity prices, the Company’s efforts in maintaining cost efficiencies achieved in 2016, the effects of the commodity price mitigation program, changes in production volumes, a current tax recovery and interest relating to the successful resolution of certain tax items previously assessed by the taxing authorities, and changes in non-cash working capital. Additional detail on changes in non-cash working capital can be found in Note 23 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Encana expects it will continue to meet the payment terms of its suppliers.

Non-GAAP Cash Flow in 2017 was $1,343 million and was primarily impacted by the items affecting cash from operating activities which are discussed below and in the Results of Operations section of this MD&A.

2017 versus 2016

Net cash from operating activities increased $425 million compared to 2016 primarily due to:

Higher realized commodity prices ($694 million), higher liquids production volumes ($83 million), lower operating expense, excluding non-cash long-term incentive costs ($73 million), lower transportation and processing expense ($56 million), higher interest income recorded in other gains ($39 million), lower restructuring costs ($34 million) and lower interest on long-term debt ($29 million);

partially offset by:

Lower realized gains on risk management included in revenues ($321 million), lower natural gas production volumes ($221 million) and changes in non-cash working capital ($66 million).

2016 versus 2015

Net cash from operating activities decreased $1,056 million compared to 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).

Investing Activities

Capital expenditures and divestitures have been Encana’s primary investing activities over the past three years. The capital spending program increased in 2017 compared to 2016 as commodity prices began to stabilize. Capital expenditures and divestiture activity are summarized in Note 3 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2017

Net cash used in investing activities in 2017 was $1,037 million primarily due to capital expenditures, partially offset by proceeds from divestitures. Capital expenditures in 2017 increased $664 million compared to 2016 due to the increase in Encana’s capital program for 2017. Capital expenditures in the Core Assets totaled $1,729 million, representing 96 percent of total capital expenditures, and increased $635 million compared to 2016, primarily in Permian ($372 million), Eagle Ford ($93 million) and Montney ($205 million). Capital expenditures exceeded cash from operating activities by $746 million and the difference was funded using cash on hand and proceeds from divestitures.

Acquisitions in 2017 were $54 million, which primarily included land purchases with oil and liquids rich potential.

Divestitures in 2017 were $736 million, which primarily included the sale of the Piceance natural gas assets in northwestern Colorado, comprising approximately 550,000 net acres of leasehold and 3,100 operated wells. Divestitures also included the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana and the sale of certain properties that did not complement Encana’s existing portfolio of assets.

2016

Net cash used in investing activities in 2016 was $29 million primarily due to capital expenditures and acquisitions, partially offset by proceeds from divestitures. Capital expenditures in 2016 decreased $1,100 million compared to 2015 due to a reduced capital program and cost savings initiatives implemented in 2016. Capital expenditures in the Core Assets totaled $1,094 million, representing 97 percent of total capital expenditures, and decreased $756 million compared to 2015, primarily in Eagle Ford ($359 million), Permian ($287 million) and Duvernay ($92 million). 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.

Divestitures in 2015 were $1,908 million, which primarily included the following:

Proceeds of approximately C$557 million ($467 million), after closing adjustments, for the sale of certain assets in Wheatland located in central and southern Alberta;

Proceeds of approximately C$450 million ($355 million), after closing adjustments, for the sale of certain natural gas gathering and compression assets in Montney located in northeastern British Columbia; and

Proceeds of approximately $769 million, after closing adjustments, for the sale of the Haynesville natural gas assets located in northern Louisiana.

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.

2017 versus 2016

Net cash used in financing activities in 2017 increased $101 million from 2016. The change was primarily due to the issuance of common shares in 2016 ($1,129 million), partially offset by a net repayment of revolving long-term debt ($650 million) and a repayment of long-term debt ($400 million) in 2016.

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) and lower cash dividend payments ($101 million).

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

2017

Encana’s long-term debt totaled $4,197 million at December 31, 2017 and there was no current portion outstanding. At December 31, 2017, 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.

The Company continues to have full access to the Credit Facilities, which remain committed through July 2020. The Credit Facilities provide financial flexibility and allow the Company to fund its operations, development activities or capital program. At December 31, 2017, Encana had no outstanding balance under the Credit Facilities.

In 2017, Encana filed a shelf registration statement in the U.S. and had access to a Canadian shelf prospectus filed in 2016, whereby the Company may issue from time to time, debt securities, common shares, Class A preferred shares, subscription receipts, warrants, units, share purchase contracts and share purchase units in Canada and/or the U.S. In 2016 and 2015, the Company filed prospectus supplements for the issuance of common shares as described below. At December 31, 2017, $4.8 billion remained accessible under the Canadian shelf prospectus. The ability to issue securities under the Canadian shelf prospectus or U.S. shelf registration statement is dependent upon market conditions.

2016

Encana’s long-term debt totaled $4,198 million at December 31, 2016 and there was no current portion outstanding.

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 12 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

On September 23, 2016, Encana completed a public offering (the “2016 Share Offering”) of 107,000,000 common shares of Encana at a price of $9.35 per common share for gross proceeds of approximately $1.0 billion ($981 million of net cash proceeds). On October 4, 2016, an over-allotment option granted to the underwriters (the “Over-Allotment Option”) to purchase up to an additional 16,050,000 common shares at a price of $9.35 per common share was exercised in full for additional gross proceeds of approximately $150 million, bringing the aggregate gross proceeds to approximately $1.15 billion ($1.13 billion of net cash proceeds). Further information on the 2016 Share Offering can be found in Note 15 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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 and no longer had access to its U.S. Commercial Paper (“U.S. CP”) program as a result of a split credit rating.

2015

Encana’s long-term debt totaled $5,333 million at December 31, 2015 and there was no current portion outstanding.

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.

In March 2015, the Company filed a prospectus supplement to the Company’s shelf prospectus (the “2015 Share Offering”) and issued 98,458,975 common shares of Encana, including common shares issued under 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).

Dividends

Encana pays quarterly dividends to shareholders at the discretion of the Board of Directors. Common shares issued in the 2016 Share Offering and 2015 Share Offering were not eligible to receive the dividends paid on September 30, 2016 and March 31, 2015, respectively.


($ millions, except as indicated)	2017		2016		2015
Dividend Payments ⁽¹⁾	$	58	$	52	$	225
Dividend Payments ($/share)		0.06		0.06		0.28

(1)	Dividend payments in 2017 included $1 million (2016 - $1 million; 2015 - $73 million) in common shares issued in lieu of cash dividends under Encana’s DRIP.

Dividend payments remained stable in 2017 after the Company reset its annualized dividend to $0.06 per common share during 2016 to better align the dividend with Encana’s cash flows and provide flexibility to use available cash for investment in the Company’s portfolio.

The dividends paid in 2015 included $73 million in common shares issued in lieu of cash dividends under Encana’s Dividend Reinvestment Plan (“DRIP”). The common shares issued under the DRIP decreased in 2016 primarily as a result of the lower dividend paid per common share in 2016 as well as Encana’s December 14, 2015 announcement that any dividends subsequent to December 31, 2015 distributed to shareholders participating in the DRIP would no longer be issued from its treasury with a discount to the average market price of the common shares.

On February 14, 2018, the Board of Directors declared a dividend of $0.015 per common share payable on March 29, 2018 to common shareholders of record as of March 15, 2018.

Off-Balance Sheet Arrangements

The Company may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. Encana’s material off-balance sheet arrangements include transportation and processing agreements, drilling rig commitments, and operating leases, as outlined in the Contractual Obligations table below, as well as undrawn letters of credit, all of which are customary agreements in the oil and gas industry. Other than the items discussed above, there are no other transactions, arrangements, or relationships with unconsolidated entities or persons that are reasonably likely to materially affect the Company’s liquidity or the availability of, or requirements for, capital resources.

Contractual Obligations

Contractual obligations arising from long-term debt, capital leases, risk management liabilities, asset retirement obligations and The Bow office building are recognized on the Company’s Consolidated Balance Sheet. The following table outlines the Company’s obligations and commitments at December 31, 2017:


	Expected Future Payments
($ millions)	2018			2019 - 2020			2021 - 2022			Thereafter			Total

Long-Term Debt	$	-		$	500		$	600		$	3,111		$	4,211

Interest Payments on Long-Term Debt		267			485			446			2,546			3,744

Capital Leases		79			173			89			33			374

Interest Payments on Capital Leases		20			25			6			5			56

Risk Management Liabilities		236			13			-			-			249

Asset Retirement Obligation ⁽¹⁾		45			279			74			957			1,355

The Bow Office Building		11			26			31			493			561

Interest Payments on The Bow Office Building		65			128			125			802			1,120

Obligations		723			1,629			1,371			7,947			11,670

Transportation and Processing		604			1,371			1,100			2,315			5,390

Drilling and Field Services		198			60			8			-			266

Operating Leases		18			32			30			46			126

Commitments ⁽¹⁾		820			1,463			1,138			2,361			5,782

Total Contractual Obligations	$	1,543		$	3,092		$	2,509		$	10,308		$	17,452

The Bow Office Building Sublease Recoveries ⁽¹⁾	$	(37	)	$	(76	)	$	(77	)	$	(636	)	$	(826	)

(1) Undiscounted.

Interest Payments on Long-Term Debt, Capital Leases and The Bow Office Building represent scheduled cash payments on the respective obligations. Further information can be found in Notes 12 and 13 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Capital Leases relates to an office building and the obligation related to the Deep Panuke Production Field Centre. Further information can be found in Note 13 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Risk Management Liabilities represents Encana’s net liability position with counterparties. Further information can be found in Note 22 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Asset Retirement Obligation represents estimated costs arising from the obligation to fund the disposal of long-lived assets upon their abandonment. The majority of Encana’s asset retirement obligations relate to the plugging of wells and related abandonment of oil and gas properties including an offshore production platform, processing plants and land or seabed restoration. Revisions to estimated retirement obligations can result from changes in regulatory requirements, changes in retirement cost estimates, revisions to estimated inflation rates and estimated timing of abandonment. Further information can be found in Note 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

The Bow Office Building relates to the 25-year lease agreement with a third party developer that commenced in 2012. Encana has recognized the accumulated construction costs for The Bow office building as an asset with a related liability. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized. Encana has subleased approximately 50 percent of The Bow office space under the lease agreement. The Bow Office Building Sublease Recoveries in the table above include the amounts expected to be recovered from the sublease. Further information can be found in Note 13 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Transportation and Processing commitments relate to contractual obligations for capacity rights with third-party pipelines and processing facilities. Drilling and Field Services commitments represent minimum future expenditures for drilling, well servicing and equipment commitment rights. Significant development commitments with joint venture partners are partially satisfied by Commitments included in the table above. Operating Leases consist of various building leases used in Encana’s daily operations.

Further to the commitments disclosed above, Encana also has various obligations that become payable if certain events occur including variable interests arising from gathering and compression agreements and guarantees on transportation commitments resulting from completed property divestitures as described in Notes 17 and 24, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

In addition, Encana has purchase orders for the purchase of inventory and other goods and services, which typically represent authorization to purchase rather than binding agreements. Encana also has obligations to fund its defined benefit pension and other post-employment benefit plans, as well as unrecognized tax benefits where the settlement is not expected within the next 12 months as described in Notes 20 and 6, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Encana may have potential exposures related to previously divested properties where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser becomes the subject of a proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, Encana could be required to perform such actions under applicable federal laws and regulations. While the Company believes that the risk of such event occurring is low, the Company could be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

Contingencies

For information on contingencies, refer to Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Accounting Policies and Estimates

Critical Accounting Estimates

The preparation of financial statements in accordance with U.S. GAAP requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. For a discussion of the Company’s significant accounting policies refer to Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment. The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to determining Encana’s financial results. Changes in the estimates and assumptions discussed below could materially affect the amount or timing of the financial results of the Company.


Description		Judgments and Uncertainties
Upstream Assets and Reserve Estimates

As Encana follows full cost accounting for oil, NGL and natural gas activities, reserves estimates are a key input to the Company’s depletion, gain or loss on divestitures and ceiling test impairment calculations. In addition, these reserves are the basis for the Company’s supplemental oil and gas disclosures.		Due to the inter-relationship of various judgments made to reserve estimates and the volatile nature of commodity prices, it is generally not possible to predict the timing or magnitude of ceiling test impairments.

Encana estimates its proved oil and gas reserves according to the definition of proved reserves provided by the SEC. The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data and must demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods and government regulations. The estimation of reserves is a subjective process.		Revisions to reserve estimates are necessary due to changes in and among other things, development plans, projected future rates of production, the timing of future expenditures, reservoir performance, economic conditions, governmental restrictions as well as changes in the expected recovery associated with infill drilling, all of which are subject to numerous uncertainties and various interpretations. Downward revisions in proved reserve estimates due to changes in reserve estimates may increase depletion expense and may also result in a ceiling test impairment.

Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.		Decreases in prices may result in reductions in certain proved reserves due to reaching economic limits at an earlier projected date and impact earnings through depletion expense and ceiling test impairments.

Encana manages its business using estimates of reserves and resources based on forecast prices and costs as it gives consideration to probable and possible reserves and future changes in commodity prices.		Encana 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 oil and natural gas properties or the future net cash flows expected to be generated from such properties.

Business Combinations

Encana follows the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as a gain in net earnings.		The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. The assumptions made in performing these valuations include discount rates, future commodity prices and costs, the timing of development activities, projections of oil and gas reserves, estimates to abandon and reclaim producing wells and tax amortization benefits available to a market participant. Changes in key assumptions may cause the acquisition accounting to be revised, including the recognition of additional goodwill or discount on acquisition. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected.

Fair value estimates are determined based on information that existed at the time of the acquisition, utilizing expectations and assumptions that would be available to and made by a market participant. When market-observable prices are not available to value assets and liabilities, the Company may use the cost, income, or market valuation approaches depending on the quality of information available to support management’s assumptions.		Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future through impairments of goodwill. In addition, differences between the future commodity prices when acquiring assets and the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net earnings.


Description		Judgments and Uncertainties

Goodwill Impairments

Goodwill is assessed for impairment at least annually in December, at the reporting unit level which are Encana’s country cost centres. To assess whether goodwill is impaired, the carrying amount of each reporting unit is determined and compared to the fair value of the reporting unit. If the carrying amount of the reporting unit is higher than its related fair value, then goodwill is measured and written down to the reporting unit’s implied fair value of goodwill. The implied fair value of goodwill is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit as if the reporting entity had been acquired in a business combination. Any excess of the carrying value of goodwill over the implied fair value of goodwill is recognized as an impairment and charged to net earnings.		The most significant assumptions used to determine a reporting unit’s fair value include estimations of oil and natural gas reserves, including both proved reserves and risk-adjusted unproved reserves, estimates of market prices considering forward commodity price curves as of the measurement date, market discount rates and estimates of operating, administrative, and capital costs adjusted for inflation. In addition, management may support fair value estimates determined with comparable companies that are actively traded in the public market, recent comparable asset transactions, and transaction premiums. This would require management to make certain judgments about the selection of comparable companies utilized.

Because quoted market prices for the Company’s reporting units are not available, management applies judgment in determining the estimated fair value of reporting units for purposes of performing goodwill impairment tests. Encana may use a combination of the income and the market valuation approaches.		Downward revisions of estimated reserves quantities, increases in future cost estimates, sustained decreases in oil or natural gas prices, or divestiture of a significant component of the reporting unit could reduce expected future cash flows and fair value estimates of the reporting units and possibly result in an impairment of goodwill in future periods.

Encana has assessed its goodwill for impairment at December 31, 2017 and no impairment was recognized as there were no indicators of impairment. The reporting units’ fair values were substantially in excess of the carrying values and as a result was not at risk of failing step one of the impairment test as at December 31, 2017.

Asset Retirement Obligation

Asset retirement obligations are those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, an offshore production platform, processing plants, and restoring land or seabed at the end of oil and gas production operations. The fair value of estimated asset retirement obligations is recogni