Quarterly Report (10-q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]

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

For the quarterly period ended September 30, 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

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 Web site, 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 Act).

Yes [ ] No [X]


		Number of registrant’s common shares outstanding as of November 3, 2017		973,114,451

ENCANA CORPORATION

FORM 10-Q

TABLE OF CONTENTS


PART I

Item 1. Financial Statements			6
Condensed Consolidated Statement of Earnings			6
Condensed Consolidated Statement of Comprehensive Income			6
Condensed Consolidated Balance Sheet			7
Condensed Consolidated Statement of Changes in Shareholders’ Equity			8
Condensed Consolidated Statement of Cash Flows			9
Notes to Condensed Consolidated Financial Statements			10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			34
Item 3. Quantitative and Qualitative Disclosures about Market Risk			56
Item 4. Controls and Procedures			57

PART II
Item 1. Legal Proceedings			58
Item 1A. Risk Factors			58
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			58
Item 3. Defaults Upon Senior Securities			58
Item 4. Mine Safety Disclosures			58
Item 5. Other Information			58
Item 6. Exhibits			58
Signatures			59

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 Quarterly Report on Form 10-Q:

“AECO” means Alberta Energy Company and is the Canadian benchmark price for natural gas.

“ASU” means Accounting Standards Update.

“bbl” or “bbls” means barrel or barrels.

“BOE” means barrels of oil equivalent.

“Btu” means British thermal units, a measure of heating value.

“DD&A” means depreciation, depletion and amortization expenses.

“FASB” means Financial Accounting Standards Board.

“Mbbls/d” means thousand barrels per day.

“MBOE/d” means thousand barrels of oil equivalent per day.

“Mcf” means thousand cubic feet.

“MD&A” means Management’s Discussion and Analysis of Financial Condition and Results of Operations.

“MMBOE” means million barrels of oil equivalent.

“MMBtu” means million Btu.

“MMcf/d” means million cubic feet per day.

“NGL” or “NGLs” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“OPEC” means Organization of the Petroleum Exporting Countries.

“SEC” means United States Securities and Exchange Commission.

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

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

“WTI” means West Texas Intermediate.

CONVERSIONS

In this Quarterly Report on Form 10-Q, 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 Quarterly Report on Form 10-Q.

FORWARD-LOOKING STATEMENTS AND RISK

This Quarterly Report on Form 10-Q contains certain forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements include: composition of the Company’s core assets, including allocation of capital and focus of development plans; growth in long-term shareholder value; statements with respect to the Company’s strategic objectives including capital allocation strategy, focus of investment, growth of high margin liquids volumes, operating efficiencies, ability to reduce costs and ability to preserve balance sheet strength; the Company’s drive for greater productivity and cost efficiencies; benefits from the Company’s multi-basin portfolio; anticipated commodity prices, production and product types; ability to accelerate activity levels and optimize well and completion designs; anticipated drilling costs and cycle times; anticipated proceeds and future benefits from various joint venture, partnership and other agreements; expected construction of compression and processing capacity and its support of the Company’s growth plans; expansion of future midstream services; estimates of reserves and resources; success of and benefits from technical innovation and cube development approach, including enhancements to productivity and recovery; anticipated returns, cash flow and leverage ratios; anticipated cash and cash equivalents and use thereof; anticipated hedging and outcomes of risk management program, including access to certain markets; potential rate escalation of transportation contracts; impact of changes in laws and regulations, including environmental legislation; financial flexibility and discipline; ability to meet financial obligations, manage debt and financial ratios and compliance with financial covenants; access to the Company’s credit facilities and other sources of financing; planned annualized dividend and the declaration and payment of future dividends, if any; adequacy of the Company’s provision for taxes and legal claims; successful resolution of certain tax items; projections and expectation of meeting the targets contained in the Company’s corporate guidance, including updates thereto; 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, including potential supply and demand factors; impact of weather; source of funding of capital spending plans; expected future interest expense; the Company’s commitments and obligations and adjustments thereto; potential future discounts, if any, in connection with the Company’s dividend reinvestment program; statements with respect to future ceiling test impairments; and the possible impact and timing of accounting pronouncements, rule changes and standards.

Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; the Company’s ability to access its revolving credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance and as specified herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of the Company’s drive for 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; enforceability of transaction agreements; and expectations and projections made in light of, and generally consistent with, Encana’s historical experience and its perception of historical trends, including with respect to the pace of technological development, the benefits achieved and general industry expectations.

Risks and uncertainties that may affect these business outcomes include: the ability to generate sufficient cash flow to meet the Company’s obligations; commodity price volatility; ability to secure adequate product transportation and potential pipeline curtailments; variability and discretion of Encana’s board of directors (the “Board of Directors”) to declare and pay dividends, if any; the timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk; risk and effect of a downgrade in credit rating, including below an investment-grade credit rating, and its impact on access to capital markets and other sources of liquidity; fluctuations in currency and interest rates; risks inherent in the Company’s corporate guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation

of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential future lawsuits and regulatory actions made against the Company; impact to the Company as a result of disputes arising with its partners, including the suspension by its partners of certain of their obligations and the inability to dispose of assets or interests in certain arrangements; the Company’s ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as “partnerships” or “joint ventures” and the funds received in respect thereof which Encana may refer to from time to time as “proceeds”, “deferred purchase price” and/or “carry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks described herein and in Item 1A. Risk Factors of the Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (“2016 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.

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 are not exhaustive. Forward-looking statements are made as of the date of this document 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 in this Quarterly Report on Form 10-Q are expressly qualified by these cautionary statements.

The reader should read carefully the risk factors described herein and in Item 1A. Risk Factors of the 2016 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

Item 1. Financial Statements

Condensed Consolidated Statement of Earnings (unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,
(US$ millions, except per share amounts)		2017		2016		2017		2016

Revenues	(Note 3)

Product revenues		$	646	$	641	$	2,112	$	1,738

Gains (losses) on risk management, net	(Note 19)		(35)		96		432		(111)

Market optimization			224		215		614		393

Other			26		27		75		76

Total Revenues			861		979		3,233		2,096

Operating Expenses	(Note 3)

Production, mineral and other taxes			27		20		80		73

Transportation and processing	(Note 19)		199		202		617		715

Operating			132		145		377		446

Purchased product			202		197		565		349

Depreciation, depletion and amortization			210		184		590		675

Impairments	(Note 8)		-		-		-		1,396

Accretion of asset retirement obligation	(Note 11)		9		12		30		38

Administrative	(Note 15)		86		91		168		231

Total Operating Expenses			865		851		2,427		3,923

Operating Income (Loss)			(4)		128		806		(1,827)

Other (Income) Expenses

Interest	(Note 5)		101		99		268		309

Foreign exchange (gain) loss, net	(Notes 6, 19)		(210)		49		(294)		(307)

(Gain) loss on divestitures, net	(Note 4)		(406)		(395)		(405)		(393)

Other (gains) losses, net	(Note 9)		(11)		(4)		(46)		(67)

Total Other (Income) Expenses			(526)		(251)		(477)		(458)

Net Earnings (Loss) Before Income Tax			522		379		1,283		(1,369)

Income tax expense (recovery)	(Note 7)		228		62		227		(706)

Net Earnings (Loss)		$	294	$	317	$	1,056	$	(663)

Net Earnings (Loss) per Common Share

Basic & Diluted	(Note 12)	$	0.30	$	0.37	$	1.09	$	(0.78)

Dividends Declared per Common Share	(Note 12)	$	0.015	$	0.015	$	0.045	$	0.045

Weighted Average Common Shares Outstanding (millions)

Basic & Diluted	(Note 12)		973.1		858.3		973.1		852.7

Condensed Consolidated Statement of Comprehensive Income (unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,
(US$ millions)		2017		2016		2017		2016

Net Earnings (Loss)		$	294	$	317	$	1,056	$	(663)

Other Comprehensive Income (Loss), Net of Tax

Foreign currency translation adjustment	(Note 13)		(97)		36		(172)		(220)

Pension and other post-employment benefit plans	(Notes 13, 17)		(1)		(1)		(2)		(1)

Other Comprehensive Income (Loss)			(98)		35		(174)		(221)

Comprehensive Income (Loss)		$	196	$	352	$	882	$	(884)

See accompanying Notes to Condensed Consolidated Financial Statements

Condensed Consolidated Balance Sheet (unaudited)


(US$ millions)		As at September 30, 2017		As at December 31, 2016

Assets

Current Assets

Cash and cash equivalents		$	889	$	834

Accounts receivable and accrued revenues			635		663

Risk management	(Notes 18, 19)		107		-

Income tax receivable			579		426

			2,210		1,923

Property, Plant and Equipment, at cost:	(Note 8)

Oil and natural gas properties, based on full cost accounting

Proved properties			39,588		39,610

Unproved properties			4,684		5,198

Other			2,312		2,194

Property, plant and equipment			46,584		47,002

Less: Accumulated depreciation, depletion and amortization			(37,890)		(38,863)

Property, plant and equipment, net	(Note 3)		8,694		8,139

Other Assets			134		138

Risk Management	(Notes 18, 19)		84		16

Deferred Income Taxes			1,429		1,658

Goodwill	(Notes 3, 4)		2,613		2,779

	(Note 3)	$	15,164	$	14,653

Liabilities and Shareholders’ Equity

Current Liabilities

Accounts payable and accrued liabilities		$	1,347	$	1,303

Income tax payable			6		5

Risk management	(Notes 18, 19)		17		254

			1,370		1,562

Long-Term Debt	(Note 9)		4,197		4,198

Other Liabilities and Provisions	(Note 10)		2,159		2,047

Risk Management	(Notes 18, 19)		11		35

Asset Retirement Obligation	(Note 11)		429		654

Deferred Income Taxes			33		31

			8,199		8,527

Commitments and Contingencies	(Note 21)

Shareholders’ Equity

Share capital - authorized unlimited common shares 2017 issued and outstanding: 973.1 million shares (2016: 973.0 million shares)	(Note 12)		4,757		4,756

Paid in surplus			1,358		1,358

Accumulated deficit			(186)		(1,198)

Accumulated other comprehensive income	(Note 13)		1,036		1,210

Total Shareholders’ Equity			6,965		6,126

		$	15,164	$	14,653

See accompanying Notes to Condensed Consolidated Financial Statements

Condensed Consolidated Statement of Changes in Shareholders’ Equity (unaudited)


Nine Months Ended September 30, 2017 (US$ millions)		Share Capital		Paid in Surplus		Accumulated Deficit		Accumulated Other Comprehensive Income		Total Shareholders’ Equity

Balance, December 31, 2016		$	4,756	$	1,358	$	(1,198)	$	1,210	$	6,126

Net Earnings (Loss)			-		-		1,056		-		1,056

Dividends on Common Shares	(Note 12)		-		-		(44)		-		(44)

Common Shares Issued Under Dividend Reinvestment Plan	(Note 12)		1		-		-		-		1

Other Comprehensive Income (Loss)	(Note 13)		-		-		-		(174)		(174)

Balance, September 30, 2017		$	4,757	$	1,358	$	(186)	$	1,036	$	6,965

Nine Months Ended September 30, 2016 (US$ millions)		Share Capital		Paid in Surplus		Accumulated Deficit		Accumulated Other Comprehensive Income		Total Shareholders’ Equity

Balance, December 31, 2015		$	3,621	$	1,358	$	(202)	$	1,390	$	6,167

Net Earnings (Loss)			-		-		(663)		-		(663)

Dividends on Common Shares	(Note 12)		-		-		(38)		-		(38)

Common Shares Issued	(Note 12)		986		-		-		-		986

Common Shares Issued Under Dividend Reinvestment Plan	(Note 12)		1		-		-		-		1

Other Comprehensive Income (Loss)	(Note 13)		-		-		-		(221)		(221)

Balance, September 30, 2016		$	4,608	$	1,358	$	(903)	$	1,169	$	6,232

See accompanying Notes to Condensed Consolidated Financial Statements

Condensed Consolidated Statement of Cash Flows (unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,
(US$ millions)		2017		2016		2017		2016

Operating Activities

Net earnings (loss)		$	294	$	317	$	1,056	$	(663)

Depreciation, depletion and amortization			210		184		590		675

Impairments	(Note 8)		-		-		-		1,396

Accretion of asset retirement obligation	(Note 11)		9		12		30		38

Deferred income taxes	(Note 7)		227		76		283		(683)

Unrealized (gain) loss on risk management	(Note 19)		76		(41)		(396)		465

Unrealized foreign exchange (gain) loss	(Note 6)		(218)		47		(317)		(223)

Foreign exchange on settlements	(Note 6)		18		(4)		27		(89)

(Gain) loss on divestitures, net	(Note 4)		(406)		(395)		(405)		(393)

Other			60		56		31		13

Net change in other assets and liabilities			(11)		(6)		(27)		(15)

Net change in non-cash working capital	(Note 20)		98		(60)		(191)		(95)

Cash From (Used in) Operating Activities			357		186		681		426

Investing Activities

Capital expenditures	(Note 3)		(473)		(205)		(1,287)		(779)

Acquisitions	(Note 4)		(2)		(67)		(50)		(69)

Proceeds from divestitures	(Note 4)		625		1,107		710		1,113

Net change in investments and other			14		(5)		93		(49)

Cash From (Used in) Investing Activities			164		830		(534)		216

Financing Activities

Net issuance (repayment) of revolving long-term debt			-		(1,493)		-		(650)

Repayment of long-term debt	(Note 9)		-		-		-		(400)

Issuance of common shares	(Note 12)		-		981		-		981

Dividends on common shares	(Note 12)		(14)		(13)		(43)		(37)

Capital lease payments and other financing arrangements	(Note 10)		(21)		(17)		(61)		(49)

Cash From (Used in) Financing Activities			(35)		(542)		(104)		(155)

Foreign Exchange Gain (Loss) on Cash and Cash

Equivalents Held in Foreign Currency			8		(1)		12		8

Increase (Decrease) in Cash and Cash Equivalents			494		473		55		495

Cash and Cash Equivalents, Beginning of Period			395		293		834		271

Cash and Cash Equivalents, End of Period		$	889	$	766	$	889	$	766

Cash, End of Period		$	39	$	33	$	39	$	33

Cash Equivalents, End of Period			850		733		850		733

Cash and Cash Equivalents, End of Period		$	889	$	766	$	889	$	766

See accompanying Notes to Condensed Consolidated Financial Statements

1. Basis of Presentation and Principles of Consolidation

Encana is in the business of the exploration for, the development of, and the production and marketing of oil, NGLs and natural gas.

The interim Condensed Consolidated Financial Statements include the accounts of Encana and entities in which it holds a controlling interest. All intercompany balances and transactions are eliminated on consolidation. Undivided interests in oil and natural gas exploration and production joint ventures and partnerships are consolidated on a proportionate basis. Investments in non-controlled entities over which Encana has the ability to exercise significant influence are accounted for using the equity method.

The interim Condensed Consolidated Financial Statements are prepared in conformity with U.S. GAAP and the rules and regulations of the SEC. Pursuant to these rules and regulations, certain information and disclosures normally required under U.S. GAAP have been condensed or have been disclosed on an annual basis only. Accordingly, the interim Condensed Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2016, which are included in Item 8 of Encana’s 2016 Annual Report on Form 10-K.

These unaudited interim Condensed Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments, with the exception of an out-of-period adjustment as described in Note 6, which are necessary to present fairly the financial position and results of the Company as at and for the periods presented. Interim condensed consolidated financial results are not necessarily indicative of consolidated financial results expected for the fiscal year.

2. Recent Accounting Pronouncements

New Standards Issued Not Yet Adopted

As of January 1, 2018, Encana will be required to adopt ASU 2014-09, “Revenue from Contracts with Customers” under Topic 606 and the related subsequent updates and clarifications issued, which will replace Topic 605, “Revenue Recognition”, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the company expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14, “Deferral of Effective Date for Revenue from Contracts with Customers”, which deferred the effective date of ASU 2014-09. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana has substantially completed evaluating the impact of ASU 2014-09 and currently expects that the standard will not have a material impact on the Company’s Consolidated Financial Statements other than enhanced disclosures related to the disaggregation of revenues from contracts with customers, the Company’s performance obligations and any significant judgments. Encana intends to adopt the new standard using the modified retrospective approach at the date of adoption.

As of January 1, 2018, Encana will be required to adopt ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendment requires the service cost component to be presented with the related employee compensation costs, while the other components of net benefit costs are required to be presented separately from the service cost component and outside the subtotal of income from operations. In addition, the amendment allows only the service cost to be eligible for capitalization. The amendment will be applied retrospectively and provides certain practical expedients for the presentation of net periodic pension costs and net periodic postretirement benefit cost, while the capitalization of the service cost component will be applied prospectively, at the date of adoption. Encana does not expect the amendment to have a material impact on the Company’s Consolidated Financial Statements.

As of January 1, 2019, Encana will be required to adopt ASU 2016-02, “Leases” under Topic 842, which will replace Topic 840 “Leases”. The new standard will require lessees to recognize right-of-use assets and related lease liabilities for all leases, including leases classified as operating leases, on the Consolidated Balance Sheet. The dual classification model was retained for the purpose of subsequent measurement and presentation of leases in the Consolidated Statement of Earnings and Consolidated Statement of Cash Flows. The new standard also expands disclosures related to the amount, timing and uncertainty of cash flows arising from leases. The standard will be applied using a modified retrospective approach and provides for certain practical expedients at the date of adoption. Encana is currently identifying, gathering and analyzing contracts impacted by the adoption of the new standard, as well as evaluating the system requirements for implementation. Although Encana is not able to reasonably estimate the financial impact of ASU 2016-02 at this time, the Company anticipates there will be a material impact on the Company’s Consolidated Financial Statements resulting from the recognition of assets and liabilities related to operating lease activities.

As of January 1, 2020, Encana will be required to adopt ASU 2017-04, “Simplifying the Test for Goodwill Impairment”. The amendment eliminates the second step of the goodwill impairment test which requires the Company to measure the impairment based on the excess amount of the carrying value of the reporting unit’s goodwill over the implied fair value of its goodwill. Under this amendment, the goodwill impairment will be measured based on the excess amount of the reporting unit’s carrying value over its respective fair value. The amendment will be applied prospectively at the date of adoption. Encana is currently in the early stages of reviewing the amendment, but does not expect the amendment to have a material impact on the Company’s Consolidated Financial Statements.

3. Segmented Information

Encana’s reportable segments are determined based on the Company’s operations and geographic locations as follows:

●

Canadian Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the Canadian cost centre.

●

USA Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the U.S. cost centre.

●

Market Optimization is primarily responsible for the sale of the Company’s proprietary production. These results are reported in the Canadian and USA Operations. Market optimization activities include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market Optimization sells substantially all of the Company’s upstream production to third party customers. Transactions between segments are based on market values and are eliminated on consolidation.

Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate. Corporate and Other also includes amounts related to sublease rentals.

Results of Operations (For the three months ended September 30)

Segment and Geographic Information


	Canadian Operations				USA Operations				Market Optimization
	2017		2016		2017		2016		2017		2016

Revenues

Product revenues	$	226	$	244	$	420	$	397	$	-	$	-

Gains (losses) on risk management, net		25		-		16		55		-		(1)

Market optimization		-		-		-		-		224		215

Other		9		2		1		6		-		-

Total Revenues		260		246		437		458		224		214

Operating Expenses

Production, mineral and other taxes		6		5		21		15		-		-

Transportation and processing		138		136		31		43		30		22

Operating		36		38		81		93		11		11

Purchased product		-		-		-		-		202		197

Depreciation, depletion and amortization		53		54		139		112		1		-

Impairments		-		-		-		-		-		-

Total Operating Expenses		233		233		272		263		244		230

Operating Income (Loss)	$	27	$	13	$	165	$	195	$	(20)	$	(16)

					Corporate & Other				Consolidated
					2017		2016		2017		2016

Revenues

Product revenues					$	-	$	-	$	646	$	641

Gains (losses) on risk management, net						(76)		42		(35)		96

Market optimization						-		-		224		215

Other						16		19		26		27

Total Revenues						(60)		61		861		979

Operating Expenses

Production, mineral and other taxes						-		-		27		20

Transportation and processing						-		1		199		202

Operating						4		3		132		145

Purchased product						-		-		202		197

Depreciation, depletion and amortization						17		18		210		184

Impairments						-		-		-		-

Accretion of asset retirement obligation						9		12		9		12

Administrative						86		91		86		91

Total Operating Expenses						116		125		865		851

Operating Income (Loss)					$	(176)	$	(64)		(4)		128

Other (Income) Expenses

Interest										101		99

Foreign exchange (gain) loss, net										(210)		49

(Gain) loss on divestitures, net										(406)		(395)

Other (gains) losses, net										(11)		(4)

Total Other (Income) Expenses										(526)		(251)

Net Earnings (Loss) Before Income Tax										522		379

Income tax expense (recovery)										228		62

Net Earnings (Loss)									$	294	$	317

Results of Operations (For the nine months ended September 30)

Segment and Geographic Information


	Canadian Operations					USA Operations					Market Optimization
	2017		2016			2017		2016			2017			2016

Revenues

Product revenues	$	787	$	664		$	1,325	$	1,074		$	-		$	-

Gains (losses) on risk management, net		6		122			30		236			-			-

Market optimization		-		-			-		-			614			393

Other		14		6			11		17			-			-

Total Revenues		807		792			1,366		1,327			614			393

Operating Expenses

Production, mineral and other taxes		16		17			64		56			-			-

Transportation and processing		403		440			141		214			73			65

Operating		89		115			252		293			23			25

Purchased product		-		-			-		-			565			349

Depreciation, depletion and amortization		170		203			368		414			1			-

Impairments		-		493			-		903			-			-

Total Operating Expenses		678		1,268			825		1,880			662			439

Operating Income (Loss)	$	129	$	(476	)	$	541	$	(553	)	$	(48)			$ (46	)

						Corporate & Other					Consolidated
						2017		2016			2017			2016

Revenues

Product revenues						$	-	$	-		$	2,112		$	1,738

Gains (losses) on risk management, net							396		(469	)		432			(111	)

Market optimization							-		-			614			393

Other							50		53			75			76

Total Revenues							446		(416	)		3,233			2,096

Operating Expenses

Production, mineral and other taxes							-		-			80			73

Transportation and processing							-		(4)			617			715

Operating							13		13			377			446

Purchased product							-		-			565			349

Depreciation, depletion and amortization							51		58			590			675

Impairments							-		-			-			1,396

Accretion of asset retirement obligation							30		38			30			38

Administrative							168		231			168			231

Total Operating Expenses							262		336			2,427			3,923

Operating Income (Loss)						$	184	$	(752	)		806			(1,827)

Other (Income) Expenses

Interest												268			309

Foreign exchange (gain) loss, net												(294	)		(307	)

(Gain) loss on divestitures, net												(405	)		(393	)

Other (gains) losses, net												(46	)		(67	)

Total Other (Income) Expenses												(477	)		(458	)

Net Earnings (Loss) Before Income Tax												1,283			(1,369	)

Income tax expense (recovery)												227			(706	)

Net Earnings (Loss)											$	1,056		$	(663	)

Intersegment Information


	Market Optimization
	Marketing Sales				Upstream Eliminations					Total
For the three months ended September 30	2017		2016		2017		2016			2017		2016

Revenues	$	918	$	963	$	(694)	$	(749)		$	224	$	214

Operating Expenses
Transportation and processing		72		65		(42)		(43)			30		22
Operating		11		11		-		-			11		11
Purchased product		854		904		(652)		(707)			202		197
Depreciation, depletion and amortization		1		-		-		-			1		-
Operating Income (Loss)	$	(20)	$	(17)	$	-	$	1		$	(20)	$	(16)

	Market Optimization
	Marketing Sales				Upstream Eliminations					Total
For the nine months ended September 30	2017		2016		2017		2016			2017		2016

Revenues	$	2,825	$	2,365	$	(2,211)	$	(1,972)		$	614	$	393

Operating Expenses
Transportation and processing		197		219		(124)		(154)			73		65
Operating		23		25		-		-			23		25
Purchased product		2,652		2,167		(2,087)		(1,818)			565		349
Depreciation, depletion and amortization		1		-		-		-			1		-
Operating Income (Loss)	$	(48)	$	(46)	$	-	$	-		$	(48)	$	(46)

Capital Expenditures
					Three Months Ended September 30,					Nine Months Ended September 30,
					2017		2016			2017		2016

Canadian Operations					$	123	$	56		$	292	$	173
USA Operations						347		149			991		605
Market Optimization						1		1			1		1
Corporate & Other						2		(1	)		3		-
					$	473	$	205		$	1,287	$	779
Goodwill, Property, Plant and Equipment and Total Assets by Segment
	Goodwill				Property, Plant and Equipment					Total Assets
	As at				As at					As at
	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016			September 30, 2017		December 31, 2016

Canadian Operations	$	700	$	650	$	780	$	602		$	1,787	$	1,542
USA Operations		1,913		2,129		6,363		6,050			9,461		9,535
Market Optimization		-		-		2		2			119		105
Corporate & Other		-		-		1,549		1,485			3,797		3,471
	$	2,613	$	2,779	$	8,694	$	8,139		$	15,164	$	14,653

4. Acquisitions and Divestitures


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Acquisitions
Canadian Operations	$	-	$	1	$	31	$	1
USA Operations		2		66		19		68
Total Acquisitions		2		67		50		69

Divestitures
Canadian Operations		(20)		(457)		(26)		(457)
USA Operations		(605)		(650)		(684)		(656)
Total Divestitures		(625)		(1,107)		(710)		(1,113)
Net Acquisitions & (Divestitures)	$	(623)	$	(1,040)	$	(660)	$	(1,044)

Acquisitions

For the nine months ended September 30, 2017, acquisitions in the Canadian and USA Operations were $31 million and $19 million, respectively, which primarily included land purchases with oil and liquids rich potential. During the three and nine months ended September 30, 2016, acquisitions primarily included the purchase of land and property in Eagle Ford with oil and liquids rich potential.

Divestitures

During the three months ended September 30, 2017, divestitures in the USA Operations comprised the sale of the Piceance natural gas assets in northwestern Colorado for proceeds of approximately $605 million, after closing and other adjustments. During the nine months ended September 30, 2017, divestitures in the USA Operations were $684 million, which primarily included the sale of the Piceance natural gas assets and the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana.

During the three and nine months ended September 30, 2016, divestitures in the USA Operations were $650 million and $656 million, respectively, which primarily included the sale of the DJ Basin assets located in northern Colorado for approximately $628 million, after closing and other adjustments.

During the three and nine months ended September 30, 2017, divestitures in the Canadian Operations were $20 million and $26 million, respectively, which primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets. For the three and nine months ended September 30, 2016, divestitures in the Canadian Operations were $457 million, which primarily included the sale of the Gordondale assets in Montney located in northwestern Alberta for approximately C$603 million ($458 million), after closing adjustments.

Amounts received from the Company’s divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost centre. For divestitures that result in a gain or loss and constitute a business, goodwill is allocated to the divestiture. Accordingly, for the three and nine months ended September 30, 2017, Encana recognized a gain of approximately $406 million, before tax, on the sale of the Company’s Piceance assets in the U.S. cost centre and allocated goodwill of $216 million. For the three and nine months ended September 30, 2016, Encana recognized a gain of approximately $397 million, before tax, on the sale of the Company’s Gordondale assets in the Canadian cost centre and allocated goodwill of $32 million.

5. Interest


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Interest Expense on:
Debt	$	67	$	72	$	200	$	229
The Bow office building		16		16		47		47
Capital leases		6		6		16		18
Other		12		5		5		15
	$	101	$	99	$	268	$	309

6. Foreign Exchange (Gain) Loss, Net

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar financing debt issued from Canada	$	(187)	$	44	$	(265)	$	(233)
Translation of U.S. dollar risk management contracts issued from Canada		(21)		(1)		(53)		5
Translation of intercompany notes		(10)		4		1		5
		(218)		47		(317)		(223)
Foreign Exchange on Settlements of:
U.S. dollar financing debt issued from Canada		3		(1)		10		(73)
U.S. dollar risk management contracts issued from Canada		(9)		-		(8)		-
Intercompany notes		15		(3)		17		(16)
Other Monetary Revaluations		(1)		6		4		5
	$	(210)	$	49	$	(294)	$	(307)

The unrealized foreign exchange (gain) loss on translation of U.S. dollar financing debt issued from Canada for the nine months ended September 30, 2017 disclosed in the table above includes an out-of-period adjustment recorded during the three months ended June 30, 2017, in respect of unrealized losses on a foreign-denominated capital lease obligation since December 2013. The cumulative impact from December 31, 2013 to June 30, 2017 recognized within foreign exchange (gain) loss in the Company’s Condensed Consolidated Statement of Earnings for the nine months ended September 30, 2017 was $68 million, before tax ($47 million, after tax). Encana has determined that the adjustment is not material to the Condensed Consolidated Financial Statements for the period ended September 30, 2017 or any prior periods. Accordingly, comparative periods presented in the Condensed Consolidated Financial Statements have not been restated.

7. Income Taxes


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Current Tax
Canada	$	-	$	(15)	$	(62)	$	(28)
United States		1		-		2		-
Other Countries		-		1		4		5
Total Current Tax Expense (Recovery)		1		(14)		(56)		(23)

Deferred Tax
Canada		71		154		91		(204)
United States		101		(98)		122		(706)
Other Countries		55		20		70		227
Total Deferred Tax Expense (Recovery)		227		76		283		(683)
Income Tax Expense (Recovery)	$	228	$	62	$	227	$	(706)
Effective Tax Rate		43.7%		16.4%		17.7%		51.6%

Encana’s interim income tax expense is determined using an estimated annual effective income tax rate applied to year-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, income tax related to foreign operations, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.

During the nine months ended September 30, 2017, the current income tax recovery was primarily due to the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years. During the three and nine months ended September 30, 2017, the deferred tax expense was primarily due to the changes in the estimated annual effective income tax rate arising from gains recognized on foreign exchange and divestitures, including allocated goodwill. During the nine months ended September 30, 2016, the deferred tax recovery was primarily due to the ceiling test impairments recognized in the Canadian and USA Operations as disclosed in Note 8.

These items noted above resulted in an effective tax rate of 17.7 percent for the nine months ended September 30, 2017, which is lower than the Canadian statutory rate of 27 percent. The effective tax rate for the nine months ended September 30, 2016 exceeded the Canadian statutory tax rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings.

8. Property, Plant and Equipment, Net


	As at September 30, 2017							As at December 31, 2016
			Accumulated							Accumulated
	Cost		DD&A			Net		Cost		DD&A			Net

Canadian Operations
Proved properties	$	14,466	$	(14,053	)	$	413	$	13,159	$	(12,896	)	$	263
Unproved properties		322		-			322		285		-			285
Other		45		-			45		54		-			54
		14,833		(14,053	)		780		13,498		(12,896	)		602

USA Operations
Proved properties		25,059		(23,079	)		1,980		26,393		(25,300	)		1,093
Unproved properties		4,362		-			4,362		4,913		-			4,913
Other		21		-			21		44		-			44
		29,442		(23,079	)		6,363		31,350		(25,300	)		6,050

Market Optimization		7		(5	)		2		6		(4	)		2
Corporate & Other		2,302		(753	)		1,549		2,148		(663	)		1,485
	$	46,584	$	(37,890	)	$	8,694	$	47,002	$	(38,863	)	$	8,139

Canadian and USA Operations property, plant and equipment include internal costs directly related to exploration, development and construction activities of $146 million, which have been capitalized during the nine months ended September 30, 2017 (2016 - $119 million). Included in Corporate and Other are $63 million ($58 million as of December 31, 2016) of international property costs, which have been fully impaired.

For the three and nine months ended September 30, 2017, as well as for the three months ended September 30, 2016, the Company did not recognize any ceiling test impairments in the Canadian or U.S. cost centres. For the nine months ended September 30, 2016, the Company recognized before-tax ceiling test impairments of $493 million in the Canadian cost centre and $903 million in the U.S. cost centre. The impairments recognized in 2016 are included with accumulated DD&A in the table above and resulted primarily from the decline in the 12-month average trailing prices which reduced proved reserves volumes and values.

The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices presented 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

Edmonton

Condensate ⁽²⁾

Henry Hub

AECO

($/bbl)

(C$/bbl)

($/MMBtu)

(C$/MMBtu)

12-Month Average Trailing Reserves Pricing ⁽¹⁾

September 30, 2017

49.81

65.30

3.01

2.64

December 31, 2016

42.75

55.39

2.49

2.17

September 30, 2016

41.68

54.07

2.28

2.05

⁽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.

Capital Lease Arrangements

The Company has several lease arrangements that are accounted for as capital leases including an office building and an offshore production platform.

As at September 30, 2017, the total carrying value of assets under capital lease was $47 million ($51 million as at December 31, 2016), net of accumulated amortization of $685 million ($648 million as at December 31, 2016). Liabilities for the capital lease arrangements are included in other liabilities and provisions in the Condensed Consolidated Balance Sheet and are disclosed in Note 10.

Other Arrangement

As at September 30, 2017, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,267 million ($1,194 million as at December 31, 2016) related to The Bow office building, which is under a 25-year lease agreement. The Bow asset is being depreciated over the 60-year estimated life of the building. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized as disclosed in Note 10.

9. Long-Term Debt


	As at		As at
	September 30,		December 31,
	2017		2016

U.S. Dollar Denominated Debt
U.S. Unsecured Notes
6.50% due May 15, 2019	$	500	$	500
3.90% due November 15, 2021		600		600
8.125% due September 15, 2030		300		300
7.20% due November 1, 2031		350		350
7.375% due November 1, 2031		500		500
6.50% due August 15, 2034		750		750
6.625% due August 15, 2037 ⁽¹⁾		462		462
6.50% due February 1, 2038 ⁽¹⁾		505		505
5.15% due November 15, 2041 ⁽¹⁾		244		244
Total Principal		4,211		4,211

Increase in Value of Debt Acquired		26		26
Unamortized Debt Discounts and Issuance Costs		(40)		(39)
Current Portion of Long-Term Debt		-		-
	$	4,197	$	4,198

⁽¹⁾	Notes accepted for purchase in the March 2016 Tender Offers.

As at September 30, 2017, total long-term debt had a carrying value of $4,197 million and a fair value of $4,845 million (as at December 31, 2016 - carrying value of $4,198 million and a fair value of $4,553 million). The estimated fair value of long-term borrowings is categorized within Level 2 of the fair value hierarchy and has been determined based on market information of long-term debt with similar terms and maturity, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.

On March 16, 2016, Encana announced tender offers (collectively, the “Tender Offers”) for certain of the Company’s outstanding senior notes (collectively, the “Notes”). The Tender Offers were for an aggregate purchase price of $250 million, excluding accrued and unpaid interest. The consideration for each $1,000 principal amount of Notes validly tendered and accepted for purchase included an early tender premium of $30 per $1,000 principal amount of Notes accepted for purchase, provided the Notes were validly tendered at or prior to the early tender date of March 29, 2016. All Notes validly tendered and accepted for purchase also received accrued and unpaid interest up to the settlement date.

On March 30, 2016, Encana announced an increase in the aggregate purchase price of the Tender Offers to $400 million, excluding accrued and unpaid interest, and accepted for purchase: i) $156 million aggregate principal amount of 5.15 percent notes due 2041; ii) $295 million aggregate principal amount of 6.50 percent notes due 2038; and iii) $38 million aggregate principal amount of 6.625 percent notes due 2037. 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, for Notes accepted for purchase. The Company used cash on hand and borrowings under its revolving credit facility to fund the Tender Offers.

Encana also recognized a gain on the early debt retirement of $103 million, before tax, representing the difference between the carrying amount of the Notes accepted for purchase and the consideration paid. The gain on the early debt retirement net of the early tender premium totaled $89 million, which is included in other (gains) losses in the Condensed Consolidated Statement of Earnings.

10. Other Liabilities and Provisions


	As at		As at
	September 30,		December 31,
	2017		2016

The Bow Office Building	$	1,354	$	1,266
Capital Lease Obligations		315		304
Unrecognized Tax Benefits		203		193
Pensions and Other Post-Employment Benefits		123		124
Long-Term Incentive Costs (See Note 16)		129		120
Other Derivative Contracts (See Notes 18, 19)		16		14
Other		19		26
	$	2,159	$	2,047

The Bow Office Building

As described in Note 8, Encana has recognized the accumulated costs for The Bow office building, which is under a 25-year lease agreement. At the conclusion of the lease term, the remaining asset and corresponding liability are expected to be derecognized. Encana has also subleased approximately 50 percent of The Bow office space under the lease agreement. The total expected future principal and interest payments related to the 25-year lease agreement and the total undiscounted future amounts expected to be recovered from the sublease are outlined below.


	2017		2018			2019			2020			2021			Thereafter			Total

Expected Future Lease Payments	$	19	$	77		$	77		$	78		$	78		$	1,380		$	1,709
Less: Amounts Representing Interest		16		66			64			64			63			868			1,141
Present Value of Expected Future
Lease Payments	$	3	$	11		$	13		$	14		$	15		$	512		$	568
Sublease Recoveries (undiscounted)	$	(10)	$	(37	)	$	(37	)	$	(38	)	$	(38	)	$	(680	)	$	(840	)

Capital Lease Obligations

As described in Note 8, the Company has several lease arrangements that are accounted for as capital leases including an office building and the Deep Panuke offshore Production Field Centre (“PFC”). Variable interests related to the PFC are described in Note 14.

The total expected future lease payments related to the Company’s capital lease obligations are outlined below.


	2017		2018		2019		2020		2021		Thereafter		Total

Expected Future Lease Payments	$	24	$	99	$	99	$	99	$	87	$	46	$	454
Less: Amounts Representing Interest		5		20		15		10		4		7		61
Present Value of Expected Future Lease Payments	$	19	$	79	$	84	$	89	$	83	$	39	$	393

11. Asset Retirement Obligation


	As at		As at
	September 30,		December 31,
	2017		2016

Asset Retirement Obligation, Beginning of Year	$	687	$ 814
Liabilities Incurred and Acquired		9	18
Liabilities Settled and Divested		(267)	(107)
Change in Estimated Future Cash Outflows		-	(99)
Accretion Expense		30	51
Foreign Currency Translation		25	10
Asset Retirement Obligation, End of Period	$	484	$ 687

Current Portion	$	55	$ 33
Long-Term Portion		429	654
	$	484	$ 687

12. Share Capital

Authorized

The Company is authorized to issue an unlimited number of no par value common shares and Class A Preferred Shares limited to a number equal to not more than 20 percent of the issued and outstanding number of common shares at the time of issuance. No Class A Preferred Shares are outstanding.

Issued and Outstanding


	As at September 30, 2017				As at December 31, 2016
	Number (millions)		Amount		Number (millions)		Amount

Common Shares Outstanding, Beginning of Year		973.0	$	4,756		849.8	$	3,621
Common Shares Issued		-		-		123.1		1,134
Common Shares Issued Under Dividend Reinvestment Plan		0.1		1		0.1		1
Common Shares Outstanding, End of Period		973.1	$	4,757		973.0	$	4,756

During the nine months ended September 30, 2017, Encana issued 49,567 common shares totaling $0.5 million under the Company’s dividend reinvestment plan (“DRIP”). During the twelve months ended December 31, 2016, Encana issued 121,249 common shares totaling $0.9 million under the DRIP.

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. After deducting underwriters’ fees and costs of the 2016 Share Offering, the net cash proceeds received were approximately $981 million. Pursuant to the 2016 Share Offering, Encana also granted the underwriters an over-allotment option (the “Over-Allotment Option”) to purchase up to an additional 16,050,000 common shares at a price of $9.35 per common share. On October 4, 2016, the Over-Allotment Option was exercised in full for additional gross proceeds of approximately $150 million. For the year ended December 31, 2016, the aggregate gross proceeds from the 2016 Share Offering, including the Over-Allotment Option, were approximately $1.15 billion. After deducting underwriters’ fees and costs of the 2016 Share Offering, the net cash proceeds received were approximately $1.13 billion.

Dividends

During the three months ended September 30, 2017, Encana paid dividends of $0.015 per common share totaling $15 million (2016 - $0.015 per common share totaling $13 million). During the nine months ended September 30, 2017, Encana paid dividends of $0.045 per common share totaling $44 million (2016 - $0.045 per common share totaling $38 million).

For the three and nine months ended September 30, 2017, the dividends paid included $0.2 million and $0.5 million, respectively, in common shares issued in lieu of cash dividends under the DRIP (for the three and nine months ended September 30, 2016 - $0.2 million and $0.8 million, respectively).

On November 7, 2017, the Board of Directors declared a dividend of $0.015 per common share payable on December 29, 2017 to common shareholders of record as of December 15, 2017.

Earnings Per Common Share

The following table presents the computation of net earnings per common share:


	Three Months Ended September 30,				Nine Months Ended September 30,
(US$ millions, except per share amounts)	2017		2016		2017		2016

Net Earnings (Loss)	$	294	$	317	$	1,056	$	(663)

Number of Common Shares:
Weighted average common shares outstanding - Basic		973.1		858.3		973.1		852.7
Effect of dilutive securities		-		-		-		-
Weighted average common shares outstanding - Diluted		973.1		858.3		973.1		852.7

Net Earnings (Loss) per Common Share
Basic & Diluted	$	0.30	$	0.37	$	1.09	$	(0.78)

Encana Stock Option Plan

Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the market value of the common shares on the date the options are granted. All options outstanding as at September 30, 2017 have associated Tandem Stock Appreciation Rights (“TSARs”) attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of the exercise over the original grant price.

In addition, certain stock options granted are performance-based whereby vesting is also subject to Encana attaining prescribed performance relative to predetermined key measures. Historically, most holders of options with TSARs have elected to exercise their stock options as a Stock Appreciation Right (“SAR”) in exchange for a cash payment. As a result, outstanding TSARs are not considered potentially dilutive securities.

Encana Restricted Share Units (“RSUs”)

Encana has a share-based compensation plan whereby eligible employees are granted RSUs. An RSU is a conditional grant to receive an Encana common share, or the cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The Company intends to settle vested RSUs in cash on the vesting date. As a result, RSUs are not considered potentially dilutive securities.

13. Accumulated Other Comprehensive Income


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Foreign Currency Translation Adjustment
Balance, Beginning of Period	$	1,125	$	1,127	$	1,200	$	1,383
Change in Foreign Currency Translation Adjustment		(97)		36		(172)		(220)
Balance, End of Period	$	1,028	$	1,163	$	1,028	$	1,163

Pension and Other Post-Employment Benefit Plans
Balance, Beginning of Period	$	9	$	7	$	10	$	7
Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 17)		-		(1)		(1)		(1)
Income Taxes		-		-		-		-
Curtailment in Net Defined Periodic Benefit Cost (See Note 17)		(1)		-		(1)		-
Income Taxes		-		-		-		-
Balance, End of Period	$	8	$	6	$	8	$	6
Total Accumulated Other Comprehensive Income	$	1,036	$	1,169	$	1,036	$	1,169

14. Variable Interest Entities

Production Field Centre

In 2008, Encana entered into a contract for the design, construction and operation of the PFC at its Deep Panuke facility. Upon commencement of operations in December 2013, Encana recognized the PFC as a capital lease asset. Under the lease contract, Encana has a purchase option and the option to extend the lease for 12 one-year terms at fixed prices after the initial lease term expires in 2021.

As a result of the purchase option and fixed price renewal options, Encana has determined it holds variable interests and that the related leasing entity qualifies as a variable interest entity (“VIE”). Encana is not the primary beneficiary of the VIE as the Company does not have the power to direct the activities that most significantly impact the VIE’s economic performance. Encana is not required to provide any financial support or guarantees to the leasing entity or its affiliates, other than the contractual payments under the lease and operating agreements. Encana’s maximum exposure is the expected lease payments over the initial contract term. As at September 30, 2017, Encana had a capital lease obligation of $332 million ($299 million as at December 31, 2016) related to the PFC.

Veresen Midstream Limited Partnership

Veresen Midstream Limited Partnership (“VMLP”) provides gathering, compression and processing services under various agreements related to the Company’s development of liquids and natural gas production in the Montney play. As at September 30, 2017, VMLP provides approximately 630 MMcf/d of natural gas gathering and compression and 652 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from up to 15 to 28 years and have various renewal terms providing up to a potential maximum of 10 years.

Encana has determined that VMLP is a VIE and that Encana holds variable interests in VMLP. Encana is not the primary beneficiary as the Company does not have the power to direct the activities that most significantly impact VMLP’s economic performance. These key activities relate to the construction, operation, maintenance and marketing of the assets owned by VMLP. The variable interests arise from certain terms under the various long-term service agreements and include: i) a take or pay for volumes in certain agreements; ii) an operating fee of which a portion can be converted into a fixed fee once VMLP assumes operatorship of certain assets; and iii) a potential payout of minimum costs in certain agreements. The potential payout of minimum costs will be assessed in the eighth year of the assets’ service period and is based on whether there is an overall shortfall of total system cash flows from natural gas gathered and compressed under certain agreements. The potential payout amount can be reduced in the event VMLP markets unutilized capacity to third party users. Encana is not required to provide any financial support or guarantees to VMLP.

As a result of Encana’s involvement with VMLP, the maximum total exposure, which represents the potential exposure to Encana in the event the assets under the agreements are deemed worthless, is estimated to be $2,245 million as at September 30, 2017. The estimate comprises the take or pay volume commitments and the potential payout of minimum costs. The take or pay volume commitments associated with certain gathering and processing assets are included in Note 21 under Transportation and Processing. The potential payout requirement is highly uncertain as the amount is contingent on future production estimates, pace of development and the amount of capacity contracted to third parties. As at September 30, 2017, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment.

15. Restructuring Charges

In February 2016, Encana announced workforce reductions to better align staffing levels and the organizational structure with the Company’s reduced capital spending program. During 2016, Encana incurred total restructuring charges of $34 million, before tax, primarily related to severance costs. As at September 30, 2017, all restructuring costs have been paid.

Restructuring charges are included in administrative expense presented in the Corporate & Other segment in the Condensed Consolidated Statement of Earnings.


	As at September 30, 2017		As at December 31, 2016

Outstanding Restructuring Accrual, Beginning of Year	$	7	$	13
Current Period Restructuring Expenses Incurred		-		34
Restructuring Costs Paid		(7)		(40)
Outstanding Restructuring Accrual, End of Period	$	-	$	7

16. Compensation Plans

Encana has a number of compensation arrangements under which the Company awards various types of long-term incentive grants to eligible employees. They include TSARs, Performance TSARs, SARs, Performance Share Units (“PSUs”), Deferred Share Units (“DSUs”) and RSUs. These compensation arrangements are share-based.

Encana accounts for TSARs, Performance TSARs, SARs, PSUs and RSUs held by employees as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.

The following weighted average assumptions were used to determine the fair value of the share units held by employees:

As at September 30, 2017

As at September 30, 2016

US$ Share
Units

C$ Share
Units

US$ Share
Units

C$ Share

Units

Risk Free Interest Rate

1.53%

0.49%

Dividend Yield

0.51%

0.53%

0.57%

0.58%

Expected Volatility Rate ⁽¹⁾

59.35%

55.21%

56.11%

52.27%

Expected Term

1.6 yrs

1.7 yrs

1.6 yrs

1.8 yrs

Market Share Price

US$11.78

C$14.69

US$10.47

C$13.71

⁽¹⁾	Volatility was estimated using historical rates.

The Company has recognized the following share-based compensation costs:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Total Compensation Costs of Transactions Classified as Cash-Settled		$ 91		$ 68		$ 84		$ 114
Less: Total Share-Based Compensation Costs Capitalized		(30)		(15)		(30)		(25)
Total Share-Based Compensation Expense (Recovery)		$ 61		$ 53		$ 54		$ 89

Recognized on the Condensed Consolidated Statement of Earnings in:
Operating		$ 18		$ 18		$ 18		$ 31
Administrative		43		35		36		58
		$ 61		$ 53		$ 54		$ 89

As at September 30, 2017, the liability for share-based payment transactions totaled $247 million ($208 million as at December 31, 2016), of which $118 million ($88 million as at December 31, 2016) is recognized in accounts payable and accrued liabilities and $129 million ($120 million as at December 31, 2016) is recognized in other liabilities and provisions in the Condensed Consolidated Balance Sheet.


	As at September 30, 2017		As at December 31, 2016

Liability for Cash-Settled Share-Based Payment Transactions:
Unvested	$	204	$	171
Vested		43		37
	$	247	$	208

The following units were granted primarily in conjunction with the Company’s February annual long-term incentive award. The TSARs and SARs were granted at the volume-weighted average trading price of Encana’s common shares for the five days prior to the grant date.


Nine Months Ended September 30, 2017 (thousands of units)

TSARs			850
SARs			349
PSUs			1,979
DSUs			148
RSUs			4,893

17. Pension and Other Post-Employment Benefits

The Company has recognized total benefit plans expense which includes pension benefits and other post-employment benefits (“OPEB”) for the nine months ended September 30 as follows:


	Pension Benefits				OPEB				Total
	2017		2016		2017		2016		2017		2016

Net Defined Periodic Benefit Cost	$	-	$	(1)	$	1	$	10	$	1	$	9
Defined Contribution Plan Expense		17		21		-		-		17		21
Total Benefit Plans Expense	$	17	$	20	$	1	$	10	$	18	$	30

Of the total benefit plans expense, $18 million (2016 - $23 million) was included in operating expense, $6 million (2016 - $7 million) was included in administrative expense and a gain of $6 million (2016 - nil) was included in other (gains) losses, net.

The net defined periodic benefit cost for the nine months ended September 30 is as follows:


	Defined Benefits				OPEB				Total
	2017		2016		2017		2016		2017		2016

Service Cost	$	1	$	1	$	6	$	8	$	7	$	9
Interest Cost		6		6		2		3		8		9
Expected Return on Plan Assets		(7)		(8)		-		-		(7)		(8)
Amounts Reclassified from Accumulated Other Comprehensive Income:
Amortization of net actuarial (gains) and losses		-		-		(1)		(1)		(1)		(1)
Curtailment		-		-		(1)		-		(1)		-
Curtailment		-		-		(5)		-		(5)		-
Total Net Defined Periodic Benefit Cost	$	-	$	(1)	$	1	$	10	$	1	$	9

18. Fair Value Measurements

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of those instruments.

Recurring fair value measurements are performed for risk management assets and liabilities and other derivative contracts, as discussed further in Note 19. These items are carried at fair value in the Condensed Consolidated Balance Sheet and are classified within the three levels of the fair value hierarchy in the following tables. There have been no significant transfers between the hierarchy levels during the period.

Fair value changes and settlements for amounts related to risk management assets and liabilities are recognized in revenues, transportation and processing expense, and foreign exchange gains and losses according to their purpose.


As at September 30, 2017	Level 1 Quoted Prices in Active Markets		Level 2 Other Observable Inputs		Level 3 Significant Unobservable Inputs		Total Fair Value		Netting ⁽¹⁾		Carrying Amount

Risk Management Assets
Commodity Derivatives:
Current assets	$	-	$	133	$	-	$	133	$	(57)	$	76
Long-term assets		-		90		-		90		(14)		76
Foreign Currency Derivatives:
Current assets		-		31		-		31		-		31
Long-term assets		-		8		-		8		-		8

Risk Management Liabilities
Commodity Derivatives:
Current liabilities	$	10	$	59	$	5	$	74	$	(57)	$	17
Long-term liabilities		1		22		2		25		(14)		11

Other Derivative Contracts
Current in accounts payable and accrued liabilities	$	-	$	5	$	-	$	5	$	-	$	5

Long-term in other liabilities and provisions		-		16		-		16		-		16

As at December 31, 2016	Level 1 Quoted Prices in Active Markets		Level 2 Other Observable Inputs		Level 3 Significant Unobservable Inputs		Total Fair Value		Netting ⁽¹⁾		Carrying Amount

Risk Management Assets
Commodity Derivatives:
Current assets	$	-	$	11	$	-	$	11	$	(11)	$	-
Long-term assets		-		19		-		19		(3)		16

Risk Management Liabilities
Commodity Derivatives:
Current liabilities	$	-	$	228	$	36	$	264	$	(11)	$	253
Long-term liabilities		-		38		-		38		(3)		35
Foreign Currency Derivatives:
Current liabilities		-		1		-		1		-		1

Other Derivative Contracts
Current in accounts payable and accrued liabilities	$	-	$	5	$	-	$	5	$	-	$	5

Long-term in other liabilities and provisions		-		14		-		14		-		14

⁽¹⁾	Netting to offset derivative assets and liabilities where the legal right and intention to offset exists, or where counterparty master netting arrangements contain provisions for net settlement.

The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, NYMEX three-way options, NYMEX costless collars, NYMEX call options, foreign currency swaps and basis swaps with terms to 2023. Level 2 also includes financial guarantee contracts as discussed in Note 19. The fair values of these contracts are based on a market approach and are estimated using inputs which are either directly or indirectly observable at the reporting date, such as exchange and other published prices, broker quotes and observable trading activity.

Level 3 Fair Value Measurements

As at September 30, 2017, the Company’s Level 3 risk management assets and liabilities consist of WTI three-way options and WTI costless collars with terms to 2018. The WTI three-way options are a combination of a sold call, bought put and a sold put. The WTI costless collars are a combination of a sold call and a bought put. These contracts allow the Company to participate in the upside of commodity prices to the ceiling of the call option and provide the Company with complete (collars)

or partial (three-way) downside price protection through the put options. The fair values of the WTI three-way options and WTI costless collars are based on the income approach and are modelled using observable and unobservable inputs such as implied volatility. The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness.

A summary of changes in Level 3 fair value measurements for the nine months ended September 30 is presented below:


	Risk Management
	2017		2016

Balance, Beginning of Year	$	(36)	$	16
Total Gains (Losses)		20		4
Purchases, Sales, Issuances and Settlements:
Settlements		9		(18)
Transfers Out of Level 3 ⁽¹⁾		-		(10)
Balance, End of Period	$	(7)	$	(8)
Change in Unrealized Gains (Losses) Related to Assets and Liabilities Held at End of Period	$	8	$	(6)

⁽¹⁾	The Company’s policy is to recognize transfers out of Level 3 on the date of the event of change in circumstances that caused the transfer.

Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:

Valuation Technique

Unobservable Input

As at
September 30,
2017

As at
December 31,
2016

Risk Management - WTI Options

Option Model

Implied Volatility

18% - 56%

18% - 64%

A 10 percent increase or decrease in implied volatility for the WTI options would cause a corresponding $1 million ($3 million as at December 31, 2016) increase or decrease to net risk management assets and liabilities.

19. Financial Instruments and Risk Management

A) Financial Instruments

Encana’s financial assets and liabilities are recognized in cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, other liabilities and provisions and long-term debt.

B) Risk Management Activities

Encana uses derivative financial instruments to manage its exposure to cash flow variability from commodity prices, electricity costs and fluctuating foreign currency exchange rates. The Company does not apply hedge accounting to any of its derivative financial instruments. As a result, gains and losses from changes in the fair value are recognized in net earnings.

Commodity Price Risk

Commodity price risk arises from the effect fluctuations in future commodity prices may have on future cash flows. To partially mitigate exposure to commodity price risk, the Company has entered into various derivative financial instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is to not use derivative financial instruments for speculative purposes.

Crude Oil and NGLs - To partially mitigate crude oil and NGL commodity price risk, the Company uses WTI-based and Mont Belvieu-based contracts such as fixed price contracts, options and costless collars. Encana also enters into basis swaps to manage against widening price differentials between various production areas and benchmark price points.

Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses NYMEX-based contracts such as fixed price contracts, options and costless collars. Encana also enters into basis swaps to manage against widening price differentials between various production areas and benchmark price points.

Power - The Company has entered into Canadian dollar denominated derivative contracts to manage its electricity consumption costs.

Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign currency exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at September 30, 2017, Encana had $135 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7503 to C$1 maturing monthly through the remainder of 2017 and $350 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7359 to C$1 maturing monthly through 2018.

Risk Management Positions as at September 30, 2017


	Notional Volumes		Term	Average Price	Fair Value

Crude Oil and NGL Contracts				US$/bbl

Fixed Price Contracts
WTI Fixed Price		33.0 Mbbls/d	2017	52.27	$	1
WTI Fixed Price		59.2 Mbbls/d	2018	52.95		24
Butane Fixed Price		2.5 Mbbls/d	2017	36.12		(2	)

WTI Three-Way Options
Sold call / bought put / sold put		25.0 Mbbls/d	2017	61.40 / 49.95 / 39.40		2

WTI Three-Way Options
Sold call / bought put / sold put		10.0 Mbbls/d	2018	54.19 / 45.00 / 35.00		(7	)

WTI Costless Collars
Sold call / bought put		30.0 Mbbls/d	2017	56.05 / 46.22		(1	)

WTI Costless Collars
Sold call / bought put		10.0 Mbbls/d	2018	57.08 / 45.00		(1	)

Basis Contracts ⁽¹⁾			2017 - 2020			(20	)
Crude Oil and NGLs Fair Value Position						(4	)

Natural Gas Contracts				US$/Mcf

Fixed Price Contracts
NYMEX Fixed Price		405 MMcf/d	2017	3.13		3
NYMEX Fixed Price		650 MMcf/d	2018	3.07		6

NYMEX Three-Way Options
Sold call / bought put / sold put		300 MMcf/d	2017	3.07 / 2.75 / 2.27		(2	)

NYMEX Costless Collars
Sold call / bought put		160 MMcf/d	2017	3.57 / 2.96		1

NYMEX Call Options
Sold call price		230 MMcf/d	2018	3.75		(8	)
Sold call price		230 MMcf/d	2019	3.75		(9	)

Basis Contracts ⁽²⁾			2017 2018 2019 2020 - 2023			13 60 39 25
Natural Gas Fair Value Position						128

Other Derivative Contracts

Fair Value Position						(21	)

Foreign Currency Contracts

Fair Value Position ⁽³⁾			2017 - 2018			39
Total Fair Value Position					$	142

⁽¹⁾	Encana has entered into swaps to protect against widening Midland, Magellan East Houston, Louisiana Light Sweet and Edmonton Condensate differentials to WTI.

⁽²⁾	Encana has entered into swaps to protect against widening AECO, Dawn, Malin and Waha basis to NYMEX.

⁽³⁾	Encana has entered into U.S. dollar denominated fixed-for-floating average currency swaps to protect against widening fluctuations between the Canadian and U.S. dollars.

Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016

Realized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues ⁽¹⁾	$	41	$	54	$	36	$	358
Transportation and processing		-		-		(4)		(4)
Foreign Currency Derivatives:
Foreign exchange		9		-		8		-
	$	50	$	54	$	40	$	354

Unrealized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues ⁽²⁾	$	(76)	$	42	$	396	$	(469)
Transportation and processing		-		(1)		-		4
Foreign Currency Derivatives:
Foreign exchange		14		-		40		-
	$	(62)	$	41	$	436	$	(465)

Total Realized and Unrealized Gains (Losses) on Risk Management, net
Commodity and Other Derivatives:
Revenues ^{(1) (2)}	$	(35)	$	96	$	432	$	(111)
Transportation and processing		-		(1)		(4)		-
Foreign Currency Derivatives:
Foreign exchange		23		-		48		-
	$	(12)	$	95	$	476	$	(111)

⁽¹⁾	Includes realized gains of $2 million and $5 million for the three and nine months ended September 30, 2017, respectively, (2016 - gains of $1 million and $4 million, respectively) related to other derivative contracts.

⁽²⁾	Includes unrealized losses of nil and $1 million for the three and nine months ended September 30, 2017, respectively, (2016 - nil and nil, respectively) related to other derivative contracts.

Reconciliation of Unrealized Risk Management Positions from January 1 to September 30

2017

2016

Fair Value

Total
Unrealized
Gain (Loss)

Fair Value of Contracts, Beginning of Year

(292)

Change in Fair Value of Contracts in Place at Beginning of Year
and Contracts Entered into During the Period

476

(111)

Settlement of Other Derivative Contracts

Fair Value of Other Derivative Contracts Entered into During the Period

(7)

Fair Value of Contracts Realized During the Period

(40)

(354)

Fair Value of Contracts, End of Period

142

436

(465)

Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value. See Note 18 for a discussion of fair value measurements.

Unrealized Risk Management Positions


	As at		As at
	September 30,		December 31,
	2017		2016

Risk Management Assets
Current	$	107	$	-
Long-term		84		16
		191		16

Risk Management Liabilities
Current		17		254
Long-term		11		35
		28		289

Other Derivative Contracts
Current in accounts payable and accrued liabilities		5		5
Long-term in other liabilities and provisions		16		14
Net Risk Management Assets (Liabilities) and Other Derivative Contracts	$	142	$	(292	)

C) Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. While exchange-traded contracts are subject to nominal credit risk due to the financial safeguards established by the New York Stock Exchange and Toronto Stock Exchange, over-the-counter traded contracts expose Encana to counterparty credit risk. This credit risk exposure is mitigated through the use of credit policies approved by the Board of Directors governing the Company’s credit portfolio including credit practices that limit transactions according to counterparties’ credit quality. Mitigation strategies may include master netting arrangements, requesting collateral and/or transacting credit derivatives. The Company executes commodity derivative financial instruments under master agreements that have netting provisions that provide for offsetting payables against receivables. As a result of netting provisions, the Company’s maximum exposure to loss under derivative financial instruments due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts, as disclosed in Note 18. As at September 30, 2017, the Company had no significant credit derivatives in place and held no collateral.

As at September 30, 2017, cash equivalents include high-grade, short-term securities, placed primarily with financial institutions and companies with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions that have investment grade credit ratings.

A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at September 30, 2017, approximately 92 percent (90 percent as at December 31, 2016) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.

As at September 30, 2017, Encana had three counterparties whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. As at September 30, 2017, these counterparties accounted for 49 percent, 11 percent and 10 percent of the fair value of the outstanding in-the-money net risk management contracts. As at December 31, 2016, Encana had one counterparty whose net settlement position accounted for 84 percent of the fair value of the outstanding in-the-money net risk management contracts.

During 2015 and 2017, Encana entered into agreements resulting from divestitures, which may require Encana to fulfill certain payment obligations on the take or pay volume commitments assumed by the purchasers. The circumstances that would require Encana to perform under the agreements include events where a purchaser fails to make payment to the guaranteed party and/or a purchaser is subject to an insolvency event. The agreements have remaining terms from four to seven years with a fair value recognized of $21 million as at September 30, 2017 ($19 million as at December 31, 2016). The maximum potential amount of undiscounted future payments is $375 million as at September 30, 2017, and is considered unlikely.

20. Supplementary Information

Supplemental disclosures to the Condensed Consolidated Statement of Cash Flows are presented below:

A) Net Change in Non-Cash Working Capital


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016

Operating Activities
Accounts receivable and accrued revenues		$ (34)		$ 28		$ 69		$ 154
Accounts payable and accrued liabilities		(82)		(59)		(253)		(250)
Income tax receivable and payable		214		(29)		(7)		1
		$ 98		$ (60)		$ (191)		$ (95)
B) Non-Cash Activities
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016

Non-Cash Investing Activities
Asset retirement obligation incurred (See Note 11)		$ 3		$ 2		$ 9		$ 6
Property, plant and equipment accruals		(18)		(23)		60		(76)
Capitalized long-term incentives (See Note 16)		30		15		30		25
Property additions/dispositions		28		30		193		85
Non-Cash Financing Activities
Common shares issued under dividend reinvestment plan (See Note 12)		$ 1		$ -		$ 1		$ 1

21. Commitments and Contingencies

Commitments

The following table outlines the Company’s commitments as at September 30, 2017:


	Expected Future Payments
(undiscounted)		2017		2018		2019		2020		2021		Thereafter		Total

Transportation and Processing	$	120	$	525	$	599	$	573	$	452	$	2,761	$	5,030
Drilling and Field Services		101		79		34		18		8		-		240
Operating Leases		4		18		16		16		15		61		130
Total	$	225	$	622	$	649	$	607	$	475	$	2,822	$	5,400

Included within transportation and processing in the table above are certain commitments associated with midstream service agreements with VMLP as described in Note 14. Divestiture transactions can reduce certain commitments disclosed above.

Contingencies

Encana is involved in various legal claims and actions arising in the normal course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encana’s financial position, cash flows or results of operations. Management’s assessment of these matters may change in the future as certain of these matters are in early stages or are subject to a number of uncertainties. For material matters that the Company believes an unfavourable outcome is reasonably possible, the Company discloses the nature and a range of potential exposures. If an unfavourable outcome were to occur, there exists the possibility of a material impact on the Company’s consolidated net earnings or loss for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. Such accruals are based on the Company’s information known about the matters, estimates of the outcomes of such matters and experience in handling similar matters.

Item 2. 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 unaudited interim Condensed Consolidated Financial Statements and accompanying notes for the period ended September 30, 2017 (“Consolidated Financial Statements”), which are included in Part I, Item 1 of this Quarterly Report on Form 10-Q and the audited Consolidated Financial Statements and accompanying notes and MD&A for the year ended December 31, 2016, which are included in Items 8 and 7, respectively, of the 2016 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 Quarterly Report on Form 10-Q. This MD&A includes the following sections:

●

Executive Overview

●

Results of Operations

●

Liquidity and Capital Resources

●

Non-GAAP Measures

Executive Overview

Strategy

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 is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. The Company is pursuing the key business objectives of exercising a disciplined capital allocation strategy by investing in a limited number of core assets, growing high margin liquids volumes, maximizing profitability through operating efficiencies and reducing costs, and preserving balance sheet strength.

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.

Encana continually reviews and evaluates its strategy and changing market conditions. In 2017, Encana continues to focus on quality growth from high margin, scalable projects located in some of the best plays in North America, referred to as the “Core Assets”, comprising Montney and Duvernay in Canada and Eagle Ford and Permian in the U.S. These world-class assets form a multi-basin portfolio enabling flexible and efficient investment of capital. The Company rapidly deploys successful ideas and practices across these assets, becoming more efficient as innovative and sustainable technical improvements are implemented.

For additional information on Encana’s strategy, its reporting segments and the plays in which the Company operates, refer to Items 1 and 2 of the 2016 Annual Report on Form 10-K. In evaluating its operations, the Company reviews performance-based measures such as Non-GAAP Cash Flow and Corporate Margin, which are non-GAAP measures and do not have any standardized meaning under U.S. GAAP. These measures may not be similar to measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. Further information regarding these measures, including reconciliations to the closest GAAP measure, can be found in the Non-GAAP Measures section of this MD&A.

Highlights

During the first nine months of 2017, Encana focused on executing its 2017 capital plan, maintaining operational efficiencies achieved in 2016 and seeking new ways to reduce costs. Higher benchmark prices in the first nine months of 2017 compared to 2016 contributed to increases in Encana’s average realized oil, NGLs and natural gas prices which resulted in higher revenues. In the first nine months of 2017, Encana’s average realized oil, NGLs and natural gas prices increased by 29 percent, 48 percent and 42 percent, respectively, compared to 2016. Encana remains committed to building a business model that allows the Company to adapt to fluctuating commodity prices.

Significant Developments

●

Closed the sale of the Company’s Piceance natural gas assets in northwestern Colorado to Caerus Oil and Gas LLC on July 25, 2017 for proceeds of approximately $605 million, after closing and other adjustments. Based on an effective date of January 1, 2017, Encana also reduced its midstream commitments by approximately $430 million (undiscounted).

●

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

Financial Results

Three months ended September 30, 2017

●

Reported net earnings of $294 million, including before-tax amounts for gain on divestitures of $406 million and foreign exchange gain of $210 million, as well as deferred tax expense of $227 million.

●

Generated cash from operating activities of $357 million and Non-GAAP Cash Flow of $270 million.

●

Achieved Corporate Margin of $10.34 per BOE.

●

Paid dividends of $0.015 per common share.

Nine months ended September 30, 2017

●

Reported net earnings of $1,056 million, including before-tax amounts for net gains on risk management in revenues of $432 million, gain on divestitures of $405 million and foreign exchange gain of $294 million, as well as deferred tax expense of $283 million.

●

Generated cash from operating activities of $681 million and Non-GAAP Cash Flow of $899 million.

●

Achieved Corporate Margin of $10.77 per BOE.

●

Recovered current taxes of approximately $56 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 $0.045 per common share.

●

Held cash and cash equivalents of $889 million and had available credit facilities of $4.5 billion for total liquidity of $5.4 billion at September 30, 2017.

Capital Investment

●

Directed $457 million, or 97 percent, of total capital spending to the Core Assets in the third quarter of 2017 and $1,240 million, or 96 percent, during the first nine months of 2017.

●

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

Production

Three months ended September 30, 2017

●

Produced average oil and NGL volumes of 127.5 Mbbls/d which accounted for 45 percent of total production volumes. Average oil and plant condensate production volumes of 103.1 Mbbls/d were 81 percent of total liquids production volumes.

●

Produced average natural gas volumes of 939 MMcf/d which accounted for 55 percent of total production volumes.

●

Reported Core Assets production of 248.0 MBOE/d, or 87 percent of total production volumes.

Nine months ended September 30, 2017

●

Produced average oil and NGL volumes of 121.2 Mbbls/d which accounted for 40 percent of total production volumes. Average oil and plant condensate production volumes of 97.2 Mbbls/d were 80 percent of total liquids production volumes.

●

Produced average natural gas volumes of 1,108 MMcf/d which accounted for 60 percent of total production volumes.

●

Reported Core Assets production of 244.0 MBOE/d, or 80 percent of total production volumes.

Operating Expenses

●

Continued to benefit from operational efficiencies achieved in 2016, which contributed to further cost savings improvements in the first nine months of 2017.

●

Reduced transportation and processing expense in the third quarter and first nine months of 2017 by $3 million, or one percent, and $98 million, or 14 percent, respectively, compared to 2016.

●

Reduced operating expense, excluding long-term incentive costs, in the third quarter and first nine months of 2017 by $13 million, or 10 percent, and $56 million, or 13 percent, respectively, compared to 2016.

2017 Outlook

Industry Outlook

The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices for the remainder of 2017 are expected to reflect global supply and demand dynamics and the geopolitical environment. At a meeting in May, OPEC decided to extend an agreement among members and certain non-OPEC countries to cut crude oil production until the end of the first quarter of 2018. The agreement, which was implemented in January 2017, has been 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 expected to meet at the end of November to further deliberate on options to rebalance the global oil market, including the possibility of extending the agreement beyond the first quarter of 2018. Additionally, in the third quarter of 2017, hurricane activity along the U.S. Gulf Coast resulted in major outages in upstream production, refining capacity and transportation infrastructure. The outages have created additional uncertainty for oil and gas supply and demand contributing to price fluctuations.

Natural gas prices were stronger in the first nine months of 2017 compared to 2016 as increases in exports and industrial demand coupled with lower natural gas production alleviated much of the oversupply. Improvement in prices going forward depends on the timing of supply and demand growth; however natural gas production in the contiguous U.S. is expected to be more than sufficient to supply continued demand growth as pipeline infrastructure additions in the U.S. Northeast help to alleviate bottlenecks and Permian Basin activity adds to associated gas production.

Company Outlook

Encana has positioned itself to be flexible and to continue to achieve strong returns from the Core Assets through this evolving commodity price cycle. The Company released updated Corporate Guidance on July 21, 2017 to reflect the impact of divestitures and improved operational performance which included changes to liquids and natural gas production volumes, upstream operating expense, transportation and processing expense and production growth from the Core Assets. The details of Encana’s Corporate Guidance can be accessed on the Company’s website at www.encana.com .

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

Capital Investment

Encana is on track to meet its full year capital investment guidance of $1.6 billion to $1.8 billion. During the first nine months of 2017, the Company spent $1,287 million, of which 96 percent was invested in the Core Assets with 55 percent directed to Permian where the Company has drilled 94 net wells. Encana continually strives to improve well performance by lowering drilling and completion costs through innovative techniques such as the cube development model, characterized as a multi-well pad centralized development on a stacked pay resource. This approach, which is currently being applied in Permian and Montney, is helping to boost productivity and enhance recovery from reservoirs in those assets.

Production

During the first nine months of 2017, average liquids production volumes were 121.2 Mbbls/d. The Company is on track to meet the updated guidance range of 127.0 Mbbls/d to 132.0 Mbbls/d by year end as a result of expected fourth quarter growth in Montney liquids volumes from new facilities in the play as well as growth in Permian oil volumes. Average natural gas production volumes for the first nine months of 2017 were 1,108 MMcf/d and are expected to remain within the updated full year 2017 guidance range of 1,075 MMcf/d to 1,125 MMcf/d at year end.

Core Assets production for the first nine months of 2017 of 244.0 MBOE/d was up slightly compared to the fourth quarter of 2016 and is expected to grow as Encana sees the anticipated benefit of its increased capital program with additional wells coming online and new facilities in Montney. Total liquids production accounted for 40 percent of the Company’s total production volumes, with the Core Assets contributing 114.8 Mbbls/d or 95 percent.

Operating Expenses

To date, efficiency improvements and lower service costs have been maintained and the Company continues to benefit from transportation contract renegotiations completed in 2016. The Company reported operating costs for the first nine months of 2017 which are on track to meet the updated full year 2017 guidance ranges. Transportation and processing expense was $6.52 per BOE, while upstream operating expense and administrative expense, excluding long-term incentive costs, were $3.85 per BOE and $1.58 per BOE, respectively. Encana continues to offset any inflationary pressures with additional efficiency gains.

Results of Operations

Selected Financial Information


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Product Revenues	$	646	$	641	$	2,112	$	1,738
Gains (Losses) on Risk Management, net		(35)		96		432		(111)
Market Optimization		224		215		614		393
Other		26		27		75		76
Total Revenues		861		979		3,233		2,096

Total Operating Expenses ⁽¹⁾		865		851		2,427		3,923
Operating Income (Loss)		(4)		128		806		(1,827)
Total Other (Income) Expenses		(526)		(251)		(477)		(458)
Net Earnings (Loss) Before Income Tax	$	522	$	379	$	1,283	$	(1,369)

Net Earnings (Loss)	$	294	$	317	$	1,056	$	(663)
(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


	Three months ended September 30,				Nine months ended September 30,
(average for the period)	2017		2016		2017		2016

Oil & NGLs
WTI ($/bbl)	$	48.21	$	44.94	$	49.47	$	41.33
Edmonton Condensate (C$/bbl)		59.59		56.22		64.62		53.42

Natural Gas
NYMEX ($/MMBtu)	$	3.00	$	2.81	$	3.17	$	2.29
AECO (C$/Mcf)		2.04		2.20		2.58		1.85
Algonquin City Gate ($/MMBtu)		2.17		2.82		3.17		2.85

Production Volumes and Realized Prices


	Three months ended September 30,								Nine months ended September 30,
	Production Volumes ⁽¹⁾				Realized Prices ⁽²⁾				Production Volumes ⁽¹⁾				Realized Prices ⁽²⁾
	2017		2016		2017		2016		2017		2016		2017		2016

Oil (Mbbls/d, $/bbl)
Canadian Operations		0.6		1.0	$	31.66	$	37.36		0.5		2.5	$	37.25	$	35.95
USA Operations		74.6		68.1		45.78		41.76		72.9		73.6		47.07		36.49
Total		75.2		69.1		45.66		41.70		73.4		76.1		47.01		36.47

NGLs – Plant Condensate (Mbbls/d, $/bbl)
Canadian Operations		22.8		19.1		46.41		40.16		20.7		17.8		47.74		39.21
USA Operations		5.1		2.7		36.63		35.83		3.1		2.7		38.95		30.37
Total		27.9		21.8		44.61		39.63		23.8		20.5		46.59		38.03

NGLs – Other (Mbbls/d, $/bbl)
Canadian Operations		4.5		6.1		22.68		20.41		4.7		8.6		21.47		10.53
USA Operations		19.9		20.0		18.37		13.11		19.3		21.3		18.11		11.16
Total		24.4		26.1		19.16		14.80		24.0		29.9		18.77		10.98

Total NGLs (Mbbls/d, $/bbl)
Canadian Operations		27.3		25.2		42.52		35.39		25.4		26.4		42.84		29.83
USA Operations		25.0		22.7		22.13		15.79		22.4		24.0		21.01		13.34
Total		52.3		47.9		32.75		26.09		47.8		50.4		32.61		21.98

Total Oil & NGLs (Mbbls/d, $/bbl)
Canadian Operations		27.9		26.2		42.28		35.47		25.9		28.9		42.74		30.36
USA Operations		99.6		90.8		39.83		35.26		95.3		97.6		40.95		30.80
Total		127.5		117.0		40.37		35.31		121.2		126.5		41.33		30.70

Natural Gas (MMcf/d, $/Mcf)
Canadian Operations		736		924		1.73		1.87		802		987		2.21		1.57
USA Operations		203		402		2.90		2.78		306		433		3.10		2.11
Total		939		1,326		1.98		2.15		1,108		1,420		2.46		1.73

Total Production (MBOE/d, $/BOE)
Canadian Operations		150.4		180.2		16.29		14.74		159.5		193.3		18.06		12.55
USA Operations		133.6		157.8		34.13		27.36		146.3		169.8		33.15		23.10
Total		284.0		338.0		24.67		20.64		305.8		363.1		25.28		17.48

Production Mix (%)
Oil & Plant Condensate		36		27						32		27
NGLs – Other		9		8						8		8
Total Oil & NGLs		45		35						40		35
Natural Gas		55		65						60		65

Core Assets Production

Oil (Mbbls/d)		71.9		61.7						69.3		65.1

NGLs – Plant Condensate (Mbbls/d)		27.4		20.9						23.2		19.2
NGLs – Other (Mbbls/d)		22.9		21.9						22.3		23.8
Total NGLs (Mbbls/d)		50.3		42.8						45.5		43.0
Total Oil & NGLs (Mbbls/d)		122.2		104.5						114.8		108.1

Natural Gas (MMcf/d)		754		830						775		911

Total Production (MBOE/d)		248.0		242.8						244.0		259.9

% of Total Encana Production		87		72						80		72

(1)

Average daily.

(2)

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

Product Revenues


	Three months ended September 30,										Nine months ended September 30,
					Natural												Natural
($ millions)	Oil		NGLs ⁽¹⁾		Gas			Total			Oil			NGLs ⁽¹⁾			Gas			Total

2016 Product Revenues	$	266	$	114	$	261		$	641		$	761		$	303		$	674		$	1,738
Increase (decrease) due to:
Sales prices		28		32		(4	)		56			211			137			229			577
Production volumes		23		10		(84	)		(51	)		(30	)		(15	)		(158	)		(203	)
2017 Product Revenues	$	317	$	156	$	173		$	646		$	942		$	425		$	745		$	2,112
(1) Includes plant condensate.

Oil Revenues

Three months ended September 30, 2017 versus September 30, 2016

Oil revenues increased $51 million compared to the third quarter of 2016 primarily due to:

●

Higher average realized oil prices of $3.96 per bbl, or nine percent, increased revenues by $28 million. The increase reflected a higher WTI benchmark price which was up seven percent. The increase was also due to higher utilization of pipelines to transport oil to more favourable markets to receive a higher net price, as well as improved regional pricing in the USA Operations; and

●

Higher average oil production volumes of 6.1 Mbbls/d increased revenues by $23 million. Higher volumes were primarily due to successful drilling programs in Permian (8.6 Mbbls/d) and Eagle Ford (4.0 Mbbls/d), partially offset by the sales of the DJ Basin (1.5 Mbbls/d) and Gordondale assets (0.7 Mbbls/d) in the third quarter of 2016 and the Tuscaloosa Marine Shale assets in the second quarter of 2017 (1.6 Mbbls/d), production constraints resulting from Hurricane Harvey in Eagle Ford and Permian during the third quarter of 2017 (1.9 Mbbls/d) and natural declines in USA Other Upstream Operations (1.0 Mbbls/d).

Nine months ended September 30, 2017 versus September 30, 2016

Oil revenues increased $181 million compared to the first nine months of 2016 primarily due to:

●

Higher average realized oil prices of $10.54 per bbl, or 29 percent, increased revenues by $211 million. The increase reflected a higher WTI benchmark price which was up 20 percent. The increase was also due to higher utilization of pipelines to transport oil to more favourable markets to receive a higher net price, as well as improved regional pricing in the USA Operations;

partially offset by:

●

Lower average oil production volumes of 2.7 Mbbls/d decreased revenues by $30 million. Lower volumes were primarily due to the sales of the DJ Basin (3.8 Mbbls/d) and Gordondale assets (1.8 Mbbls/d) in the third quarter of 2016 and the Tuscaloosa Marine Shale assets in the second quarter of 2017 (1.0 Mbbls/d), natural declines in the USA Other Upstream Operations (2.0 Mbbls/d) and Eagle Ford (1.4 Mbbls/d) and production constraints resulting from Hurricane Harvey in Eagle Ford and Permian during the third quarter of 2017 (0.6 Mbbls/d), partially offset by a successful drilling program in Permian (8.3 Mbbls/d).

NGL Revenues

Three months ended September 30, 2017 versus September 30, 2016

NGL revenues increased $42 million compared to the third quarter of 2016 primarily due to:

●

Higher average realized NGL prices of $6.66 per bbl, or 26 percent, increased revenues by $32 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up seven percent and six 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 $10 million. Higher volumes were primarily due to successful drilling programs in the Core Assets (10.2 Mbbls/d), partially offset by the sales of the Gordondale (1.7 Mbbls/d) and DJ Basin assets (1.5 Mbbls/d) in the third quarter of 2016 and the Piceance natural gas assets in the third quarter of 2017 (0.8 Mbbls/d), production constraints resulting from Hurricane Harvey in Eagle Ford and Permian during the third quarter of 2017 (0.8 Mbbls/d) and natural declines in Other Upstream Operations (0.7 Mbbls/d).

Nine months ended September 30, 2017 versus September 30, 2016

NGL revenues increased $122 million compared to the first nine months of 2016 primarily due to:

●

Higher average realized NGL prices of $10.63 per bbl, or 48 percent, increased revenues by $137 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 20 percent and 21 percent, respectively. The increase was also due to a shift in the NGL production mix to higher value condensate compared to 2016;

partially offset by:

●

Lower average NGL production volumes of 2.6 Mbbls/d decreased revenues by $15 million. Lower volumes were primarily due to asset sales (8.9 Mbbls/d) which mainly includes the sales of the Gordondale and DJ Basin assets in the third quarter of 2016 and natural declines in Other Upstream Operations (0.8 Mbbls/d), partially offset by successful drilling programs in the Core Assets (7.4 Mbbls/d).

Natural Gas Revenues

Three months ended September 30, 2017 versus September 30, 2016

Natural gas revenues decreased $88 million compared to the third quarter of 2016 primarily due to:

●

Lower average realized natural gas prices of $0.17 per Mcf, or eight percent, decreased revenues by $4 million. The decrease reflected a lower AECO benchmark price which was down seven percent; and

●

Lower average natural gas production volumes of 387 MMcf/d decreased revenues by $84 million. Lower volumes were primarily due to the sale of the Piceance natural gas assets in the third quarter of 2017 (169 MMcf/d) and the sales of the Gordondale (28 MMcf/d) and DJ Basin assets (15 MMcf/d) in the third quarter of 2016, natural declines in Other Upstream Operations (120 MMcf/d), lower natural gas volumes in Montney due to natural declines and Encana’s focus on liquids rich wells in the play (51 MMcf/d), and increased downtime resulting from scheduled third-party plant maintenance in Montney (11 MMcf/d), partially offset by a successful drilling program in Permian (22 MMcf/d).

Nine months ended September 30, 2017 versus September 30, 2016

Natural gas revenues increased $71 million compared to the first nine months of 2016 primarily due to:

●

Higher average realized natural gas prices of $0.73 per Mcf, or 42 percent, increased revenues by $229 million. The increase reflected higher NYMEX, AECO and Algonquin City Gate benchmark prices which were up 38 percent, 39 percent and 11 percent, respectively;

partially offset by:

●

Lower average natural gas production volumes of 312 MMcf/d decreased revenues by $158 million. Lower volumes were primarily due to natural declines in Other Upstream Operations (74 MMcf/d), the sales of the Gordondale (70 MMcf/d) and DJ Basin assets (36 MMcf/d) in the third quarter of 2016, the sale of the Piceance natural gas assets in the third quarter of 2017 (57 MMcf/d), lower natural gas volumes in Montney due to natural declines and Encana’s focus on liquids rich wells in the play (49 MMcf/d) and increased downtime resulting from scheduled third-party plant maintenance in Montney (27 MMcf/d), partially offset by a successful drilling program in Permian (15 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 September 30, 2017 can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Realized Gains (Losses) on Risk Management
Commodity Price
Oil	$	14	$	70	$	30	$	242
NGLs ⁽¹⁾		4		-		5		-
Natural Gas		21		(16)		(4)		112
Other ⁽²⁾		2		-		5		4
Total		41		54		36		358

Unrealized Gains (Losses) on Risk Management		(76)		42		396		(469)
Total Gains (Losses) on Risk Management, Net	$	(35)	$	96	$	432	$	(111)

	Three months ended September 30,				Nine months ended September 30,
(Per-unit)	2017		2016		2017		2016

Realized Gains (Losses) on Risk Management
Commodity Price
Oil ($/bbl)	$	2.12	$	11.09	$	1.51	$	11.59
NGLs ⁽¹⁾ ($/bbl)	$	0.58	$	(0.10)	$	0.33	$	(0.01)
Natural Gas ($/Mcf)	$	0.25	$	(0.13)	$	(0.01)	$	0.29
Total ($/BOE)	$	1.50	$	1.74	$	0.37	$	3.55

(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.


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Market Optimization	$	224	$	215	$	614	$	393

Three months ended September 30, 2017 versus September 30, 2016

Market Optimization revenues increased $9 million compared to the third quarter of 2016 primarily due to:

●

Higher commodity prices ($38 million), partially offset by lower sales of third-party purchased volumes used for optimization activities ($29 million).

Nine months ended September 30, 2017 versus September 30, 2016

Market Optimization revenues increased $221 million compared to the first nine months of 2016 primarily due to:

●

Higher commodity prices ($160 million) and higher sales of third-party purchased volumes used for optimization activities ($61 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 10 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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.


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Canadian Operations	$	6	$	5	$	16	$	17
USA Operations		21		15		64		56
Total	$	27	$	20	$	80	$	73

	Three months ended September 30,				Nine months ended September 30,
($/BOE)	2017		2016		2017		2016

Canadian Operations	$	0.42	$	0.28	$	0.37	$	0.31
USA Operations	$	1.69	$	1.05	$	1.59	$	1.20
Total	$	1.01	$	0.64	$	0.95	$	0.73

Three months ended September 30, 2017 versus September 30, 2016

Production, mineral and other taxes increased $7 million compared to the third quarter of 2016 primarily due to:

●

Higher commodity prices in the USA Operations and higher oil production volumes in Permian and Eagle Ford ($7 million);

partially offset by:

●

The sale of the Piceance natural gas assets in the third quarter of 2017 and the sale of the DJ Basin assets in the third quarter of 2016 ($2 million).

Nine months ended September 30, 2017 versus September 30, 2016

Production, mineral and other taxes increased $7 million compared to the first nine months of 2016 primarily due to:

●

Higher commodity prices in the USA Operations and higher oil production volumes in Permian ($22 million);

partially offset by:

●

The recovery of certain production taxes in the USA Operations ($8 million) and 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 ($7 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.


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Canadian Operations	$	138	$	136	$	403	$	440
USA Operations		31		43		141		214
Upstream Transportation and Processing		169		179		544		654

Market Optimization		30		22		73		65
Corporate & Other		-		1		-		(4)
Total	$	199	$	202	$	617	$	715

	Three months ended September 30,				Nine months ended September 30,
($/BOE)	2017		2016		2017		2016

Canadian Operations	$	10.00	$	8.23	$	9.26	$	8.30
USA Operations	$	2.55	$	2.96	$	3.53	$	4.60
Upstream Transportation and Processing	$	6.50	$	5.77	$	6.52	$	6.57

Three months ended September 30, 2017 versus September 30, 2016

Transportation and processing expense decreased $3 million compared to the third quarter of 2016 primarily due to:

●

The sales of the Piceance natural gas assets in the third quarter of 2017 ($19 million) and the Gordondale and DJ Basin assets in the third quarter of 2016 ($6 million);

partially offset by:

●

Rate escalation of certain transportation contracts ($7 million), the higher U.S./Canadian dollar exchange rate ($6 million), higher volumes and prices in Permian ($5 million) and increased downstream processing costs in Montney and Duvernay due to Encana’s focus on liquids rich wells in the play ($4 million).

Nine months ended September 30, 2017 versus September 30, 2016

Transportation and processing expense decreased $98 million compared to the first nine months of 2016 primarily due to:

●

The sales of the Gordondale and DJ Basin assets ($55 million) in the third quarter of 2016 and the Piceance natural gas assets in the third quarter of 2017 ($19 million), the renegotiation and expiration of certain transportation contracts ($37 million) and lower natural gas volumes and lower gas gathering and processing fees in Montney and Other Upstream Operations ($18 million);

partially offset by:

●

Higher volumes and prices in Permian ($17 million), increased downstream processing costs in Montney and Duvernay due to Encana’s focus on liquids rich wells in the plays ($12 million) and the higher U.S./Canadian dollar exchange rate ($6 million).

Operating

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


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Canadian Operations	$	36	$	38	$	89	$	115
USA Operations		81		93		252		293
Upstream Operating Expense		117		131		341		408

Market Optimization		11		11		23		25
Corporate & Other		4		3		13		13
Total	$	132	$	145	$	377	$	446

	Three months ended September 30,				Nine months ended September 30,
($/BOE)	2017		2016		2017		2016

Canadian Operations	$	2.50	$	2.29	$	1.97	$	2.13
USA Operations	$	6.57	$	6.37	$	6.17	$	6.25
Upstream Operating Expense ⁽¹⁾	$	4.41	$	4.19	$	3.98	$	4.06

(1)

Upstream Operating Expense per BOE for the third quarter and the first nine months of 2017 includes long-term incentive costs of $0.45/BOE and $0.13/BOE, respectively (2016 - $0.44/BOE and $0.24/BOE, respectively).

Three months ended September 30, 2017 versus September 30, 2016

Operating expense decreased $13 million compared to the third quarter of 2016 primarily due to:

●

Asset sales which primarily included the sales of the Piceance natural gas assets in the third quarter of 2017, the DJ Basin assets in the third quarter of 2016 and the Tuscaloosa Marine Shale assets in the second quarter of 2017 ($18 million) and lower salaries and benefits due to a lower headcount ($10 million);

partially offset by:

●

Higher activity in Permian, Eagle Ford and Montney ($14 million).

Nine months ended September 30, 2017 versus September 30, 2016

Operating expense decreased $69 million compared to the first nine months of 2016 primarily due to:

●

Asset sales which primarily included the sales of 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 ($40 million), lower salaries and benefits due to a lower headcount ($28 million), cost-saving initiatives ($21 million) and lower long-term incentive costs resulting from the decrease in Encana’s share price in the first nine months of 2017 ($13 million);

partially offset by:

●

Higher activity in Permian and Eagle Ford ($29 million).

Further information on Encana’s long-term incentives can be found in Note 16 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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.


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Market Optimization	$	202	$	197	$	565	$	349

Three months ended September 30, 2017 versus September 30, 2016

Purchased product expense increased $5 million compared to the third quarter of 2016 primarily due to:

●

Higher commodity prices ($34 million), partially offset by lower third-party volumes purchased for optimization activities ($29 million).

Nine months ended September 30, 2017 versus September 30, 2016

Purchased product expense increased $216 million compared to the first nine months of 2016 primarily due to:

●

Higher commodity prices ($153 million) and higher third-party volumes purchased for optimization activities ($63 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 the 2016 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. For additional information on Critical Accounting Estimates, refer to the MD&A included in Item 7 of the 2016 Annual Report on Form 10-K. Corporate assets are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets.


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Canadian Operations	$	53	$	54	$	170	$	203
USA Operations		139		112		368		414
Upstream DD&A		192		166		538		617

Market Optimization		1		-		1		-
Corporate & Other		17		18		51		58
Total	$	210	$	184	$	590	$	675

	Three months ended September 30,				Nine months ended September 30,
($/BOE)	2017		2016		2017		2016

Canadian Operations	$	3.84	$	3.21	$	3.89	$	3.83

USA Operations	$	11.31	$	7.69	$	9.22	$	8.89

Upstream DD&A	$	7.35	$	5.30	$	6.44	$	6.20

Three months ended September 30, 2017 versus September 30, 2016

DD&A increased $26 million compared to the third quarter of 2016 primarily due to:

●

Higher depletion rates primarily in the USA Operations ($49 million), partially offset by lower production volumes ($24 million).

The depletion rate increased $2.05 per BOE compared to the third quarter of 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 the sale of the DJ Basin assets in the third quarter of 2016.

Nine months ended September 30, 2017 versus September 30, 2016

DD&A decreased $85 million compared to the first nine months of 2016 primarily due to:

●

Lower production volumes ($89 million).

The depletion rate increased $0.24 per BOE compared to the first nine months of 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.

For the third quarter and first nine months of 2017, 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 in the third quarter of 2016 were deducted from the U.S. full cost pool. Additional information on the divestitures can be found in Note 4 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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.

The Company did not recognize any ceiling test impairments for the third quarter and the first nine months of 2017. Ceiling test impairments in the first nine months of 2016 in the Canadian and USA Operations were $493 million and $903 million, respectively. The ceiling test impairments 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⁾

September 30, 2017

49.81

65.30

3.01

2.64

December 31, 2016

42.75

55.39

2.49

2.17

September 30, 2016

41.68

54.07

2.28

2.05

(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 the MD&A included in Item 7 of the 2016 Annual Report on Form 10-K.

Administrative

Administrative expense represents costs associated with corporate functions provided by Encana staff in the Calgary and Denver offices. Costs primarily include salaries and benefits, general office, information technology and long-term incentive costs.


	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016

Administrative ($ millions)	$	86	$	91	$	168	$	231
Administrative ($/BOE)	$	3.31	$	2.94	$	2.02	$	2.33

Administrative expense in the third quarter of 2017 decreased $5 million from 2016 primarily due to lower third party payments relating to previously divested assets ($9 million) as well as lower office costs ($3 million), partially offset by higher long-term incentive costs resulting from the increase in Encana’s share price in the third quarter of 2017 ($8 million). Administrative expense per BOE for the third quarter of 2017 includes long-term incentive costs of $1.68/BOE compared to long-term incentive costs and restructuring costs of $1.10/BOE and $0.04/BOE, respectively, in 2016.

Administrative expense in the first nine months of 2017 decreased $63 million from 2016 primarily due to lower restructuring costs ($33 million) and lower long-term incentive costs resulting from the decrease in Encana’s share price in the first nine months of 2017 ($22 million). Administrative expense per BOE for the first nine months of 2017 includes long-term incentive costs of $0.44/BOE compared to long-term incentive costs and restructuring costs of $0.58/BOE and $0.33/BOE, respectively, in 2016.

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 $33 million during the first nine months of 2016. There were no restructuring costs in the first nine months of 2017. Further information on restructuring costs can be found in Note 15 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Other (Income) Expenses


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Interest	$	101	$	99	$	268	$	309

Foreign exchange (gain) loss, net		(210)		49		(294)		(307)

(Gain) loss on divestitures, net		(406)		(395)		(405)		(393)

Other (gains) losses, net		(11)		(4)		(46)		(67)

Total Other (Income) Expenses	$	(526)	$	(251)	$	(477)	$	(458)

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 obligation for The Bow office building and capital leases.

Interest expense in the first nine months of 2017 decreased $41 million compared to 2016 primarily due to lower interest on debt ($29 million) and lower other interest expense ($10 million).

Lower interest on debt in first nine months of 2017 is primarily due to 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. Lower other interest expense in the first nine months of 2017 is primarily due to the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years.

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. In the third quarter and first nine months of 2017, the average U.S./Canadian dollar foreign exchange rate was 0.798 and 0.766, respectively, compared to 0.766 and 0.757, respectively for 2016. The period end U.S./Canadian dollar foreign exchange rates as at September 30, 2017 and December 31, 2016 were 0.801 and 0.745, respectively.

In the third quarter of 2017, Encana recorded a net foreign exchange gain compared to a net loss in 2016 ($259 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 foreign exchange losses in 2016 ($231 million) and higher unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada compared to 2016 ($20 million).

In the first nine months of 2017, Encana recorded a lower net foreign exchange gain compared to 2016 ($13 million). The lower net foreign exchange gain was primarily due to foreign exchange losses on the settlement of U.S. dollar financing debt issued from Canada and intercompany notes compared to foreign exchange gains in 2016 ($116 million), partially offset by unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada compared to foreign exchange losses in 2016 ($58 million) and higher unrealized foreign exchange gains on the translation of U.S. dollar financing debt issued from Canada compared to 2016 ($32 million). In the first nine months of 2017, unrealized foreign exchange on the translation of U.S. dollar financing debt issued from Canada includes an out-of-period adjustment of

$68 million, before tax, in respect of cumulative unrealized losses on a foreign-denominated capital lease obligation from December 31, 2013 to June 30, 2017. Further information on the out-of-period adjustment can be found in Note 6 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

(Gains) Losses on Divestitures, Net

Amounts received from the Company’s divestiture transactions are deducted from the respective Canadian and U.S. full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost centre, in which case a gain or loss is recognized. Additional information on gains on divestitures can be found in Note 4 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Gain on divestitures in the third quarter and first nine months of 2017 primarily includes the before tax gain on the sale of the Piceance natural gas assets. Gain on divestitures in the third quarter and first nine months of 2016 primarily includes the before tax gain on the sale of the Gordondale assets in the third quarter of 2016. Further information on the divestitures can be found in the Liquidity and Capital Resources section of this MD&A.

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.

Other gains in the first nine months of 2017 primarily includes interest received of $33 million resulting from the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years.

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

Income Tax


	Three months ended September 30,				Nine months ended September 30,
($ millions)	2017		2016		2017		2016

Current Income Tax Expense (Recovery)	$	1	$	(14)	$	(56)	$	(23)

Deferred Income Tax Expense (Recovery)		227		76		283		(683)

Income Tax Expense (Recovery)	$	228	$	62	$	227	$	(706)

Effective Tax Rate		43.7%		16.4%		17.7%		51.6%

Income Tax Expense (Recovery)

Three months ended September 30, 2017 versus September 30, 2016

In the third quarter of 2017, Encana recorded a higher income tax expense compared to 2016 primarily due to a higher deferred tax expense as a result of changes in the estimated annual effective income tax rate arising from gains recognized on foreign exchange and divestitures, including allocated goodwill.

Nine months ended September 30, 2017 versus September 30, 2016

In the first nine months of 2017, Encana recorded an income tax expense compared to an income tax recovery in 2016 primarily due to operating income in 2017 compared to an operating loss in 2016.

The current income tax recovery in the first nine months of 2017 was primarily due to the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years.

The deferred tax expense in the first nine months of 2017 was primarily due to changes in the estimated annual effective income tax rate arising from gains recognized on foreign exchange and divestitures, including allocated goodwill. The deferred tax recovery in the first nine months of 2016 was primarily due to the recognition of ceiling test impairments.

Effective Tax Rate

Encana’s interim income tax expense is determined using the estimated annual effective income tax rate applied to year-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, income tax related to foreign operations, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. These items resulted in an effective tax rate for the third quarter of 2017 that is higher than the Canadian statutory rate of 27 percent and an effective tax rate for the first nine months of 2017 that is below the Canadian statutory rate. The effective tax rate for the first nine months of 2017 was also impacted by the tax reassessments discussed above.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As a result, there are tax matters under review for which the timing of resolution is uncertain. The Company believes that the provision for income taxes is adequate.

Liquidity and Capital Resources

Sources of Liquidity

The Company has the flexibility to access cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities as well as debt and equity capital markets. Encana closely monitors the accessibility of cost-effective credit and ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. In addition, the Company may use cash and cash equivalents, cash from operating activities, or proceeds from asset divestitures and share issuances to fund its operations and service debt repayments. At September 30, 2017, $384 million in cash and cash equivalents was held by U.S. subsidiaries. The cash held by U.S. subsidiaries is accessible and may be subject to additional Canadian income taxes and U.S. withholding taxes if repatriated.

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


	As at September 30,
($ millions, except as indicated)	2017		2016

Cash and Cash Equivalents	$	889	$	766

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

Available Credit Facility – U.S. Subsidiary ⁽¹⁾		1,500		1,500
Total Liquidity		5,389		5,266

Long-Term Debt		4,197		4,198

Total Shareholders’ Equity		6,965		6,232

Debt to Capitalization (%) ⁽²⁾		38		40

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

(1)

Collectively, the “Credit Facilities”.

(2)

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

(3)

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

Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is a non-GAAP measure defined in the Non-GAAP Measures section of this MD&A, as a proxy for Encana’s financial covenant under the Credit Facilities, which requires debt to adjusted capitalization to be less than 60 percent. The definitions used in the covenant under the Credit Facilities adjust capitalization for cumulative historical ceiling test impairments that were recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Additional information on financial covenants can be found in Note 13 to the Consolidated Financial Statements included in Item 8 of the 2016 Annual Report on Form 10-K.

Sources and Uses of Cash

In the third quarter and first nine months of 2017, Encana primarily generated cash through proceeds from divestitures and operating activities. The following table summarizes the sources and uses of the Company’s cash and cash equivalents.


			Three months ended September 30,				Nine months ended September 30,
($ millions)	Activity Type		2017		2016		2017		2016

Sources of Cash and Cash Equivalents

Cash from operating activities		Operating	$	357	$	186	$	681	$	426

Proceeds from divestitures		Investing		625		1,107		710		1,113

Issuance of common shares		Financing		-		981		-		981

Other		Investing		14		-		93		-
				996		2,274		1,484		2,520

Uses of Cash and Cash Equivalents

Capital expenditures		Investing		473		205		1,287		779

Acquisitions		Investing		2		67		50		69

Net repayment of revolving long-term debt		Financing		-		1,493		-		650

Repayment of long-term debt		Financing		-		-		-		400

Dividends on common shares		Financing		14		13		43		37

Other		Investing/Financing		21		22		61		98
				510		1,800		1,441		2,033

Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency				8		(1)		12		8
Increase (Decrease) in Cash and Cash Equivalents			$	494	$	473	$	55	$	495

Operating Activities

Cash from operating activities can be significantly impacted by fluctuations in commodity prices, operating costs, and changes in production volumes. In the first nine months of 2017, cash from operating activities 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 tax authorities, and changes in non-cash working capital. Additional detail on changes in non-cash working capital can be found in Note 20 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. Encana expects it will continue to meet the payment terms of its suppliers.

Non-GAAP Cash Flow in the third quarter and first nine months of 2017 was $270 million and $899 million, respectively. Non-GAAP Cash Flow 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. Non-GAAP Cash Flow excludes changes in non-cash working capital as disclosed in the Non-GAAP Measures section of this MD&A.

Three months ended September 30, 2017 versus September 30, 2016

Net cash from operating activities increased $171 million compared to the third quarter of 2016 primarily due to:

●

Higher realized commodity prices ($56 million) and changes in non-cash working capital ($158 million);

partially offset by:

●

Lower production volumes ($51 million).

Nine months ended September 30, 2017 versus September 30, 2016

Net cash from operating activities increased $255 million compared to the first nine months of 2016 primarily due to:

●

Higher realized commodity prices ($577 million), lower transportation and processing expense ($98 million), lower operating expense, excluding non-cash long-term incentive costs ($50 million), lower interest on long-term debt and other ($39 million), higher interest income recorded in other gains ($37 million), a higher current tax recovery ($33 million) and lower restructuring costs ($33 million);

partially offset by:

●

Lower realized gains on risk management included in revenues ($322 million), lower production volumes ($203 million) and changes in non-cash working capital ($96 million).

Investing Activities

Net cash used in investing activities in the first nine months of 2017 was $534 million primarily due to capital expenditures, partially offset by proceeds from divestitures. Capital expenditures in the first nine months of 2017 increased $508 million compared to 2016 due to an increase in the capital program for 2017. Capital expenditures in the Core Assets totaled $1,240 million, representing 96 percent of total capital expenditures, and increased $493 million compared to 2016, primarily in Permian ($285 million), Eagle Ford ($90 million) and Montney ($130 million). Capital expenditures exceeded cash from operating activities by $606 million and the difference was funded using cash on hand and proceeds from divestitures.

Divestitures in the first nine months of 2017 were $710 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.

Divestitures in the first nine months of 2016 were $1,113 million, which primarily included the sale of the DJ Basin assets in northern Colorado, comprising approximately 51,000 net acres, and the sale of the Gordondale assets which included approximately 54,200 net acres of land and associated infrastructure in Montney located in northwestern Alberta.

Acquisitions in the first nine months of 2017 and 2016 were $50 million and $69 million, respectively, which primarily included land purchases with oil and liquids rich potential.

Capital expenditures and acquisition and divestiture activity are summarized in Notes 3 and 4 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Financing Activities

Net cash used in financing activities in the first nine months of 2017 decreased $51 million from 2016 primarily due to a net repayment of revolving long-term debt ($650 million) and a repayment of long-term debt ($400 million) in the first nine months of 2016, partially offset by the issuance of common shares in the first nine months of 2016 ($981 million).

Encana’s long-term debt totaled $4,197 million at September 30, 2017 and $4,198 million at December 31, 2016. There was no current portion outstanding at September 30, 2017 or December 31, 2016. At September 30, 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.

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 9 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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 September 30, 2017, Encana had no outstanding balance under the Credit Facilities.

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 12 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Dividends

Encana pays quarterly dividends to shareholders at the discretion of the Board of Directors.


	Three months ended September 30,				Nine months ended September 30,
($ millions, except as indicated)	2017		2016		2017		2016

Dividend Payments	$	15	$	13	$	44	$	38
Dividend Payments ($/share)	$	0.015	$	0.015	$	0.045	$	0.045

On November 7, 2017, the Board of Directors declared a dividend of $0.015 per common share payable on December 29, 2017 to common shareholders of record as of December 15, 2017.

Off-Balance Sheet Arrangements

For information on off-balance sheet arrangements and transactions, refer to the Off-Balance Sheet Arrangements section of the MD&A included in Item 7 of the 2016 Annual Report on Form 10-K.

Commitments and Contingencies

For information on commitments and contingencies, refer to Note 21 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Non-GAAP Measures

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. These measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Non-GAAP Cash Flow, Corporate Margin and Debt to Adjusted Capitalization. Management’s use of these measures is discussed further below.

Non-GAAP Cash Flow and Corporate Margin

Non-GAAP Cash Flow is a non-GAAP measure defined as cash from (used in) operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and current tax on sale of assets.

Corporate Margin is a non-GAAP measure defined as Non-GAAP Cash Flow per BOE of production.

Management believes these measures are useful to the Company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, and are an indication of the Company’s ability to generate cash to finance capital programs, to service debt and to meet other financial obligations. These measures are used, along with other measures, in the calculation of certain performance targets for the Company’s management and employees.


	Three months ended September 30,				Nine months ended September 30,
($ millions, except as indicated)	2017		2016		2017		2016

Cash From (Used in) Operating Activities	$	357	$	186	$	681	$	426

(Add back) deduct:

Net change in other assets and liabilities		(11)		(6)		(27)		(15)

Net change in non-cash working capital		98		(60)		(191)		(95)

Current tax on sale of assets		-		-		-		-

Non-GAAP Cash Flow	$	270	$	252	$	899	$	536

Production Volumes (MMBOE)		26.1		31.1		83.5		99.5

Corporate Margin ($/BOE)	$	10.34	$	8.10	$	10.77	$	5.39

Debt to Adjusted Capitalization

Debt to Adjusted Capitalization is a non-GAAP measure which adjusts capitalization for historical ceiling test impairments that were recorded as at December 31, 2011. Management monitors Debt to Adjusted Capitalization as a proxy for Encana’s financial covenant under the Credit Facilities which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders’ equity and an equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP.


($ millions, except as indicated)	September 30, 2017		December 31, 2016

Debt	$	4,197	$	4,198

Total Shareholders’ Equity		6,965		6,126

Equity Adjustment for Impairments at December 31, 2011		7,746		7,746

Adjusted Capitalization	$	18,908	$	18,070

Debt to Adjusted Capitalization		22%		23%

Item 3: Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Encana’s potential exposure to market risks. The term “market risk” refers to the Company’s risk of loss arising from adverse changes in oil, NGL and natural gas prices, foreign currency exchange rates and interest rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. The Company’s policy is to not use derivative financial instruments for speculative purposes.

COMMODITY PRICE RISK

Commodity price risk arises from the effect fluctuations in future commodity prices, including oil, NGLs and natural gas may have on future revenues, expenses and cash flows. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to the Company’s natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable as discussed in Item 1A. “Risk Factors” of the 2016 Annual Report on Form 10-K. To partially mitigate exposure to commodity price risk, the Company may enter into various derivative financial instruments including futures, forwards, swaps, options and costless collars. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors and may vary from time to time. Both exchange traded and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 19 under Part I, Item 1 of this Quarterly Report on Form 10-Q.

The table below summarizes the sensitivity of the fair value of the Company’s risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:


	September 30, 2017
(US$ millions)	10% Price Increase		10% Price Decrease

Crude oil price	$	(164)	$	162

NGL price		(2)		2

Natural gas price		(14)		7

FOREIGN EXCHANGE RISK

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. As Encana operates in Canada and the United States, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Company’s reported results. Although Encana’s financial results are consolidated in Canadian dollars, the Company reports its results in U.S. dollars as most of its revenues are closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies.

Foreign exchange gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated and settled, and primarily include:

●

U.S. dollar denominated financing debt issued from Canada

●

U.S. dollar denominated risk management assets and liabilities held in Canada

●

U.S. dollar denominated cash and short-term investments held in Canada

●

Foreign denominated intercompany loans

To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at September 30, 2017, Encana had $135 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7503 to C$1 maturing monthly through the remainder of 2017 and $350 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7359 to C$1 maturing monthly through 2018.

As at September 30, 2017, Encana had $4.2 billion in U.S. dollar long-term debt and $332 million in U.S. dollar capital leases issued from Canada that were subject to foreign exchange exposure.

The table below summarizes the sensitivity to foreign exchange rate fluctuations, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact from Canadian to U.S. foreign currency exchange rate changes. Fluctuations in foreign currency exchange could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:


	September 30, 2017
(US$ millions)	10% Rate Increase		10% Rate Decrease

Foreign currency exchange	$	(227)	$	277

INTEREST RATE RISK

Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company’s financial assets or liabilities. The Company may partially mitigate its exposure to interest rate changes by holding a mix of both fixed and floating rate debt and may also enter into interest rate derivatives to partially mitigate effects of fluctuations in market interest rates.

As at September 30, 2017, the Company had no floating rate debt and there were no interest rate derivatives outstanding.

Item 4: Controls and Procedures

DISCLOSURE CONTROLS AND PROCEDURES

Encana’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (“Exchange Act”). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2017.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in Encana’s internal control over financial reporting during the third quarter of 2017 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II

Item 1. Legal Proceedings

On September 16, 2016, the Colorado Oil and Gas Conservation Commission (“COGCC”) issued a Notice of Alleged Violation to Hunter Ridge Energy Services LLC (“HRES”), a subsidiary of Encana, citing a violation of Rule 907.a. of the COGCC Rules of Practice and Procedure, 2 CCR 404-1, for failure to manage exploration and production waste in a manner protective of waters of the state, relating to a pipeline release discovered in June 2016 in Garfield County, Colorado. On September 7, 2017, the COGCC recommended an Administrative Order by Consent (“AOC”) that included a civil penalty against HRES of $222,500. HRES executed the AOC as of September 11, 2017 and the civil penalty was paid in full settlement of the matter.

Please also refer to Item 3 of the 2016 Annual Report on Form 10-K and Note 21 of Encana’s Condensed Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors in the 2016 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits


Exhibit No		Description
31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Schema Document.
101.CAL		XBRL Calculation Linkbase Document.
101.DEF		XBRL Definition Linkbase Document.
101.LAB		XBRL Label Linkbase Document.
101.PRE		XBRL Presentation Linkbase Document.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.