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

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 innon-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,~~2017, which are included in Item 8 of Encana’s ~~2016~~2017 Annual Report on Form10-K.

The interim Condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2017, except as noted below in Note 2. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements.

These unaudited interim Condensed Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments, with the exception of anout-of-period adjustment for the three and six months ended June 30, 2017 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.

~~New Standards Issued Not Yet Adopted~~Changes in Accounting Policies and Practices

~~As of~~On January 1, 2018, Encana ~~will be required to adopt~~ adopted the following ASUs issued by the FASB, which have not had a material impact on the Company's interim Condensed Consolidated Financial Statements:

As of January 1, 2019, Encana will be required to adopt ASU2016-02, “Leases” under Topic 842, which will replace Topic 840 “Leases”. The new standard will require lessees to recognizeright-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~~Topic 842 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~~In January 2018, FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”, which permits entities to elect an optional transition practical expedient for land easements that were not previously accounted for as leases under Topic 840. The expedient provides prospective application of Topic 842 to all new or modified land easements upon adoption of the new ~~standard,~~standard. Encana intends to elect this transitional practical expedient. Topic 842 also allows a short-term lease exemption which does not require a right-of-use asset and lease liability to be recognized on the Consolidated Balance Sheet when the lease term is 12 months or less, including any renewal periods which are reasonably certain to be exercised. Encana intends to elect the short-term lease exemption.

Encana continues to review and analyze contracts, identify its portfolio of leased assets, gather the necessary terms and data elements, as well as ~~evaluating~~identify the processes and controls required to support the accounting for leases and related disclosures. The Company is in the process of implementing a lease software system ~~requirements~~which will facilitate the measurement and required disclosures for ~~implementation.~~operating leases. The Company anticipates the software implementation to be complete by the end of 2018. Although Encana is not able to reasonably estimate the financial impact of ~~ASU2016-02~~Topic 842 at this time, the Company anticipates there will be an increase in right of use assets and lease liabilities on the Consolidated Financial Statements.

As of January 1, 2019, Encana will be required to adopt ASU 2018-02 “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments allow for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (“U.S. Tax Reform”). Amendments can be applied either in the period of adoption or retrospectively to each period in which the effect of the rate change from the U.S. Tax Reform is recognized. While Encana has other post-employment benefit plans which were affected by the U.S. Tax Reform, the impact is not material ~~impact on~~to the Company’s Consolidated Financial ~~Statements resulting from~~Statements. As a result, the ~~recognition of assets and liabilities related~~Company does not intend to ~~operating lease activities.~~take the election provided in the amendment.

As of January 1, 2020, Encana will be required to adopt ASU2017-04, “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.

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

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.

~~Acquisitions~~The following tables summarize the Company’s revenues from contracts with customers and other sources of revenues. Encana presents realized and unrealized gains and losses on certain derivative contracts within revenues.

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.

The Company’s revenues from contracts with customers consists of product sales including oil, NGLs and natural gas, as well as the provision of gathering and processing services to third parties. Encana had no contract asset or liability balances during the periods presented. As at June 30, ~~2017, divestitures~~2018, receivables and accrued revenues from contracts with customers were $715 million ($676 million as at December 31, 2017).

Performance obligations arising from product sales contracts are typically satisfied at a point in time when the ~~USA Operations comprised~~product is delivered to the ~~sale~~customer and control is transferred. Payment from the customer is due when the product is delivered to the custody point. The Company’s product sales are sold under short-term contracts with terms that are less than one year at either fixed or market index prices or under long-term contracts exceeding one year at market index prices.

As at June 30, 2018, all remaining performance obligations are priced at market index prices or are variable volume delivery contracts. As such, the variable consideration is allocated entirely to the wholly unsatisfied performance obligation or promise to deliver units of production, and revenue is recognized at the amount for which the Company has the right to invoice the product delivered.

Performance obligations arising from arrangements to gather and process natural gas on behalf of third parties are typically satisfied over time as the service is provided to the customer. Payment from the customer is due when the customer receives the benefit of the ~~Piceance natural gas assets in northwestern Colorado~~service and the product is delivered to the custody point or plant tailgate. The Company’s gathering and processing services are provided on an interruptible basis with transaction prices that are for ~~proceeds~~fixed prices and/or variable

consideration. Variable consideration received is related to recovery 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 saleplant operating costs or escalation of the ~~Piceance natural gas assets and~~fixed price based on a consumer price index. As the ~~sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana.~~service contracts are interruptible, with service provided on an “as available” basis, there are no unsatisfied performance obligations remaining at June 30, 2018.

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~~six months ended ~~September~~June 30, ~~2016, divestitures in the Canadian Operations were $457~~2018, other includes $11 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 allocatedinterest recovered due to the ~~divestiture. Accordingly, for the three~~resolution of certain tax items relating to prior taxation years (2017 - $13 million and ~~nine months ended September 30, 2017, Encana recognized a gain of approximately $406~~$17 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.

The unrealized foreign exchange (gain) loss on translation of U.S. dollar financing debt issued from Canada for the ~~nine~~three and six months ended ~~September~~June 30, 2017 disclosed in the table above ~~includes~~included anout-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~~three and six months ended ~~September~~June 30, 2017 was $68 million, before tax ($47 million, after tax). Encana ~~has~~ determined that the adjustment iswas not material to the Condensed Consolidated Financial Statements for the period ended ~~September~~June 30, 2017 or any prior periods. ~~Accordingly, comparative periods presented in the Condensed Consolidated Financial Statements have not been restated.~~

Encana’s interim income tax expense is determined using anthe estimated annual effective income tax rate applied toyear-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, the effect of legislative changes including U.S. Tax Reform, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.

During the ~~nine~~three and six months ended ~~September~~June 30, 2018, the current income tax recovery was primarily due to the resolution of certain tax items relating to prior taxation years. During the three and six months ended June 30, 2017, the current income tax recovery was primarily due to the successful resolution of certain tax items previously assessed by the ~~tax~~taxing 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~~The effective tax rate of ~~17.7~~100 percent for the ~~nine~~six months ended ~~September~~June 30, ~~2017, which~~2018 is ~~lower~~higher than the Canadian statutory rate of 27 ~~percent.~~percent primarily due to the current year items discussed above. The effective tax rate of (0.1) percent for the ~~nine~~six months ended ~~September~~June 30, ~~2016 exceeded~~2017 is lower than 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.~~

During the six months ended June 30, 2018, there was no change to the provisional tax adjustment recognized in 2017 resulting from the re-measurement of the Company’s tax position due to a reduction of the U.S. federal corporate tax rate under U.S. Tax Reform. The provisional amount recognized may change due to additional regulatory guidance that may be issued, and from additional analysis or changes in interpretation and assumptions of the U.S. Tax Reform made by the Company.

For the six months ended June 30, 2018, acquisitions in the Canadian and USA Operations were $2 million (2017 - $31 million) and nil (2017 - $17 million), respectively, which primarily included land purchases with oil and liquids rich potential.

For the six months ended June 30, 2018, divestitures in the Canadian Operations were $57 million, which primarily included the sale of the Pipestone midstream assets located in Alberta. During the six months ended June 30, 2017, divestitures in the Canadian Operations were $6 million, which primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets.

For the six months ended June 30, 2018, divestitures in the USA Operations were $8 million, which primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets. During the six months ended June 30, 2017, divestitures in the USA Operations were $79 million, which primarily included the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana.

Amounts received from the Company’s divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools.

Canadian and USA Operations property, plant and equipment include internal costs directly related to exploration, development and construction activities of ~~$146~~$109 million, which have been capitalized during the ~~nine~~six months ended ~~September~~June 30, ~~2017 (2016~~2018 (2017 - ~~$119~~$77 million). Included in Corporate and Other are ~~$63~~$59 million ($5863 million as ofat December 31, ~~2016)~~2017) 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.~~

~~The12-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.

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~~June 30, ~~2017,~~2018, the total carrying value of assets under capital lease was ~~$47~~$44 million ($5146 million as at December 31, ~~2016)~~2017), net of accumulated amortization of ~~$685~~$664 million ($~~648~~684 million as at December 31, ~~2016)~~2017). 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.~~11.

As at ~~September~~June 30, ~~2017,~~2018, Corporate and Other property, plant and equipment and total assets include a carrying value of ~~$1,267~~$1,185 million ($~~1,194~~1,255 million as at December 31, ~~2016)~~2017) related to The Bow office building, which is under a25-year lease agreement. The Bow asset is being depreciated over the60-year estimated life of the building. At the conclusion of the~~25-year~~ 25‑year term, the remaining asset and corresponding liability are expected to be derecognized as disclosed in Note ~~10.~~11.

As at ~~September~~June 30, ~~2017,~~2018, total long-term debt had a carrying value of $4,198 million and a fair value of $4,792 million (as at December 31, 2017 - 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~~$5,042 million). The estimated fair value of long-term borrowings is categorized within Level 2 of the fair value hierarchy and has been determined based on market information of long-term debt with similar terms and maturity, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.

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.

As described in Note 8,9, Encana has recognized the accumulated costs for The Bow office building, which is under a25-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 the25-year lease agreement and the total undiscounted future amounts expected to be recovered from the sublease are outlined below.

As described in Note 8,9, the Company has several lease arrangements that are accounted for as capital leases including an office building and the Deep Panuke offshore Production Field Centre (“PFC”). Variable interests related to the PFC are described in Note ~~14.~~15.

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

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.

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, Encana issued ~~49,567~~31,212 common shares totaling ~~$0.5~~$0.4 million under the Company’s dividend reinvestment plan (“DRIP”). During the twelve months ended December 31, ~~2016,~~2017, Encana issued ~~121,249~~58,480 common shares totaling ~~$0.9~~$0.6 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.

During the three months ended ~~September~~June 30, ~~2017,~~2018, Encana paid dividends of $0.015 per common share totaling ~~$15~~$14 million ~~(2016~~(2017 - $0.015 per common share totaling ~~$13~~$14 million). During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, Encana paid dividends of ~~$0.045~~$0.03 per common share totaling ~~$44~~$29 million ~~(2016~~(2017 - ~~$0.045~~$0.03 per common share totaling ~~$38~~$29 million).

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, the dividends paid included ~~$0.2~~$0.1 million and ~~$0.5~~$0.4 million, respectively, in common shares issued in lieu of cash dividends under the DRIP (for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 - ~~$0.2~~$0.1 million and ~~$0.8~~$0.3 million, respectively).

On ~~November 7, 2017,~~July 31, 2018, the Board of Directors declared a dividend of $0.015 per common share payable on ~~December 29, 2017~~September 28, 2018 to common shareholders of record as of ~~December 15, 2017.~~September 14, 2018.

On February 26, 2018, the Company announced it received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019. The Company has authorization from its Board to spend up to $400 million on the NCIB.

All purchases are made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess is allocated to retained earnings/accumulated deficit.

For the six months ended June 30, 2018, the Company purchased approximately 16.8 million common shares for total consideration of approximately $200 million. Of the amount paid, $83 million was charged to share capital and $117 million was charged to accumulated deficit.

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

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~~June 30, ~~2017~~2018 have associated Tandem Stock Appreciation Rights (“TSARs”) attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of the exercise over the original grant price.

In addition, certain stock options granted are performance-based 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 has a share-based compensation plan whereby eligible employees and Directors are granted RSUs. An RSU is a conditional grant to receive the equivalent of an Encana common share ~~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~~currently settles vested RSUs in ~~cash on the vesting date.~~cash. As a result, RSUs are not considered potentially dilutive securities.

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 12one-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~~June 30, ~~2017,~~2018, Encana had a capital lease obligation of ~~$332~~$278 million ($~~299~~314 million as at December 31, ~~2016)~~2017) related to the PFC.

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~~June 30, ~~2017,~~2018, VMLP provides approximately ~~630~~1,150 MMcf/d of natural gas gathering and compression and ~~652~~887 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from up to 1513 to 2827 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~~$2,382 million as at ~~September~~June 30, ~~2017.~~2018. The estimate comprises the take or pay volume commitments and the potential payout of minimum costs. The take or pay volume commitments associated with certain gathering and processing assets are included in Note 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~~June 30, ~~2017,~~2018, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment.

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

Encana accounts for TSARs, Performance TSARs, SARs, PSUs and RSUs 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~~June 30, ~~2017,~~2018, the liability for share-based payment transactions totaled ~~$247~~$319 million ($~~208~~327 million as at December 31, ~~2016)~~2017), of which ~~$118~~$267 million ($88152 million as at December 31, ~~2016)~~2017) is recognized in accounts payable and accrued liabilities and ~~$129~~$52 million ($~~120~~175 million as at December 31, ~~2016)~~2017) is recognized in other liabilities and provisions in the Condensed Consolidated Balance Sheet.

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

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

Of the total benefit plans expense, ~~$18~~$11 million ~~(2016~~(2017 - ~~$23~~$12 million) was included in operating expense $6and $4 million ~~(2016~~(2017 - $7$4 million) was included in administrative ~~expense and a gain of $6 million (2016 - nil) was included in other (gains) losses, net.~~expense.

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

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.

The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, ~~NYMEXthree-way~~ ~~options, NYMEX costless collars,~~fixed price swaptions, 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.

As at ~~September~~June 30, ~~2017,~~2018, the Company’s Level 3 risk management assets and liabilities consist of WTIthree-way options and WTI costless collars with terms to ~~2018.~~2019. The WTIthree-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 WTIthree-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~~six months ended ~~September~~June 30 is presented below:

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

A 10 percent increase or decrease in implied volatility for the WTI options would cause a corresponding $1$7 million ($32 million as at December 31, ~~2016)~~2017) increase or decrease to net risk management assets and liabilities.

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

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

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

Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses NYMEX-based contracts such as fixed price contracts, ~~options~~fixed price swaptions and ~~costless collars.~~options. Encana has also ~~enters~~entered 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 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~~June 30, ~~2017,~~2018, Encana ~~had $135~~has entered into $358 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$~~0.7503~~0.7606 to C$1, ~~maturing~~which mature monthly through the remainder of ~~2017~~2018 and ~~$350~~$250 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$~~0.7359~~0.7581 to C$1, ~~maturing~~which mature monthly ~~through 2018.~~

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

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

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.

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,~~the TSX, over-the-counter traded contracts expose Encana to counterparty credit risk. This credit risk exposure is mitigated through the use of credit policies approved by the Board of Directors governing the Company’s credit portfolio including credit practices that limit transactions according to counterparties’ credit quality. Mitigation strategies may include master netting arrangements, requesting collateral and/or transacting credit derivatives. The Company executes commodity derivative financial instruments under master agreements that have netting provisions that provide for offsetting payables against receivables. As a result of netting provisions, the Company’s maximum exposure to loss under derivative financial instruments due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts, as disclosed in Note 18. As at ~~September~~June 30, ~~2017,~~2018, the Company had no significant credit derivatives in place and held no collateral.

As at ~~September~~June 30, ~~2017,~~2018, cash equivalents include high-grade, short-term securities, placed primarily with financial institutions and companies with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions that have investment grade credit ratings.

A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at ~~September~~June 30, ~~2017,~~2018, approximately 92 percent ~~(90~~(92 percent as at December 31, ~~2016)~~2017) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.

As at ~~September~~June 30, ~~2017,~~2018, Encana had ~~three~~two counterparties whose net settlement position individually accounted for more than 10 percent of the fair value of the outstandingin-the-money net risk management contracts by counterparty. As at ~~September~~June 30, ~~2017,~~2018, these counterparties accounted for ~~49 percent, 11~~47 percent and 1011 percent of the fair value of the outstandingin-the-money net risk management contracts. As at December 31, ~~2016,~~2017, Encana had ~~one counterparty~~three counterparties whose net settlement position accounted for 8456 percent, 11 percent and 11 percent of the fair value of the outstandingin-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~~three to ~~seven~~six years with a fair value recognized of ~~$21~~$17 million as at ~~September~~June 30, ~~2017~~2018 ($19 million as at December 31, ~~2016)~~2017). The maximum potential amount of undiscounted future payments is ~~$375~~$287 million as at ~~September~~June 30, ~~2017,~~2018, and is considered unlikely.

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

The following table outlines the Company’s commitments as at ~~September~~June 30, ~~2017:~~2018:

Included within transportation and processing in the table above are certain commitments associated with midstream service agreements with VMLP as described in Note ~~14.~~15. Divestiture transactions can reduce certain commitments disclosed above.

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~~June 30, ~~2017~~2018 (“Consolidated Financial Statements”), which are included in Part I, Item 1 of this Quarterly Report on Form10-Q and the audited Consolidated Financial Statements and accompanying notes and MD&A for the year ended December 31, ~~2016,~~2017, which are included in Items 8 and 7, respectively, of the ~~2016~~2017 Annual Report on Form10-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 Form10-Q. This MD&A includes the following sections:

Encana is a leading North American energy producer that is focused on developing its multi-basin portfolio of oil, ~~NGL~~NGLs 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,~~2018, 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~~2017 Annual Report on Form10-K. In evaluating its operations and assessing its leverage, the Company reviews performance-based measures such asNon-GAAP Cash Flow and ~~Corporate~~Non-GAAP Cash Flow Margin and debt-based metrics such as Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA, which arenon-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 theNon-GAAP Measures section of this MD&A.

During the first ~~nine~~six months of ~~2017,~~2018, Encana focused on executing its ~~2017~~2018 capital plan, maintaining operational efficiencies achieved in ~~2016~~2017 and ~~seeking new ways to reduce~~minimizing the effect of inflationary costs. Higher ~~benchmark prices~~revenues in the first ~~nine~~six months of ~~2017~~2018 compared to ~~2016~~2017 resulting from higher liquids production volumes and benchmark prices. Liquids production volumes increased by 27 percent compared to 2017. Higher oil and NGL benchmark prices contributed to increases in Encana’s average realized oil ~~NGLs~~ and ~~natural gas~~NGL 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~~36 percent and 4231 percent, ~~respectively, compared~~respectively. Encana is also focused on the diversification of the Company’s downstream markets to ~~2016.~~capture higher realized prices. Encana remains committed to ~~building~~delivering a business model that allows the Company to adapt to fluctuating commodity prices.

Received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019. As of June 30, 2018, the Company has purchased approximately 16.8 million common shares for total consideration of approximately $200 million.

●

Announced an agreement with Keyera Partnership, a subsidiary of Keyera Corp., on April 2, 2018 to sell the Company’s Pipestone liquids hub in Alberta. In conjunction with the sale, Keyera will own and construct a natural gas processing facility and provide Encana with processing services under a competitive fee-for-service arrangement in support of the Company’s liquids growth plans in Montney.

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~~June 30, ~~2017~~2018

Reported net loss of $151 million, including a net loss on risk management in revenues of $312 million, before tax, and net foreign exchange loss of $25 million, before tax.

Recovered current taxes of approximately $64 million and interest of $11 million primarily resulting from the resolution of certain tax items relating to prior taxation years.

Generated cash from operating activities of $475 million, Non-GAAP Cash Flow of $586 million and Non-GAAP Cash Flow Margin of $19.09 per BOE, including the tax items noted above.

●

~~Reported net earnings of $294 million, includingbefore-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.~~

Paid dividends of $0.015 per common share.

●

~~Generated cash from operating activities of $357 million andNon-GAAP~~ ~~Cash Flow of $270 million.~~

●

~~Achieved Corporate Margin of $10.34 per BOE.~~

●

~~Paid dividends of $0.015 per common share.~~

~~Nine~~Six months ended ~~September~~June 30, ~~2017~~2018

Reported net earnings of nil, including a net loss on risk management in revenues of $276 million, before tax, and net foreign exchange loss of $116 million, before tax.

Recovered current taxes of approximately $61 million and interest of $11 million primarily resulting from the resolution of certain tax items relating to prior taxation years.

Generated cash from operating activities of $856 million, Non-GAAP Cash Flow of $986 million and Non-GAAP Cash Flow Margin of $16.46 per BOE, including the tax items noted above.

Paid dividends of $0.03 per common share.

Held cash and cash equivalents of $336 million and had available credit facilities of $4.0 billion for total liquidity of $4.3 billion at June 30, 2018.

Capital Investment

Directed $420 million, or 71 percent, of total capital spending in Permian and Montney in the second quarter of 2018 and $813 million, or 74 percent, during the first six months of 2018.

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

●

~~Reported net earnings of $1,056 million, includingbefore-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 andNon-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~~June 30, ~~2017~~2018

Produced average oil and NGL volumes of 155.3 Mbbls/d which accounted for 46 percent of total production volumes. Average oil and plant condensate production volumes of 118.3 Mbbls/d were 76 percent of total liquids production volumes.

●

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 1,095 MMcf/d which accounted for 54 percent of total 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~~Six months ended ~~September~~June 30, ~~2017~~2018

●

Produced average oil and NGL volumes of 150.3 Mbbls/d which accounted for 45 percent of total production volumes. Average oil and plant condensate production volumes of 115.7 Mbbls/d were 77 percent of total liquids production volumes.

Produced average natural gas volumes of 1,085 MMcf/d which accounted for 55 percent of total production volumes.

Revenues 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

Focused on market diversification to other downstream markets to maximize realized commodity prices and revenues through a combination of derivative financial instruments and transportation contracts.

●

~~Continued to benefit from~~

Secured pipeline transportation capacity to the Dawn and Houston markets to protect against weakening AECO and Midland differentials to NYMEX and WTI, respectively; maintained access to local markets through existing transportation contracts.

Preserved operational efficiencies achieved in previous years and minimized the effect of inflationary costs.

Incurred higher transportation and processing expense in the second quarter and the first six months of 2018 of $66 million, or 32 percent, and $103 million, or 25 percent, respectively, compared to the same periods 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~~primarily due to higher volumes in Montney and additional costs incurred in conjunction with the diversification of other downstream markets to capture higher realized prices.

2018 Outlook

Industry Outlook

The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices ~~for the remainder of 2017~~during 2018 are expected to reflect global supply and demand dynamics ~~and~~as well as the geopolitical environment. ~~At a meeting in May,~~The original OPEC ~~decided to extend an~~ agreement ~~among members and certainnon-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~~to limit output and the drawdowns of oil storage inventory levels were generally supportive of oil prices in ~~2017; however,~~the first half of 2018. At a meeting in June 2018, OPEC and certain non-OPEC countries agreed to increase future oil production, ~~growth in other countries continues to partially offset~~which could negatively impact prices for the ~~expected benefit~~remainder of the ~~OPEC agreement. OPEC is expected to meet at the end of November to further deliberate on options to rebalance the global~~year. Conversely, 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~~supply outages resulting from geopolitical instability in major ~~outages in upstream production, refining capacity and transportation infrastructure. The outages have created additional uncertainty~~producing countries could positively impact prices for ~~oil and gas supply and demand contributing to price fluctuations.~~the remainder of the year.

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 on2018 will be affected by the timing of supply and demand ~~growth; however~~growth. Natural gas prices in western Canada have seen significant negative price pressure as supply reached multi-year highs, surpassing regional demand and stressing effective pipeline capacity. Stronger condensate prices may also lend support to activity levels resulting in continued downward pressure on natural gas prices in the second half of 2018. Potential for improvement in U.S. natural gas prices remains limited due to continued substantial production increases in Northeast U.S. and associated gas production in the ~~contiguous U.S.~~Permian Basin.

Company Outlook

Encana 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~~in the current price environment in order to continue to achieve strong ~~returns from the Core Assets through this evolving commodity price cycle.~~returns. 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~~which mitigate price volatility and help sustain revenues during periods of lower prices. A portion of the Company’s production is sold at prevailing market prices which also allows Encana to

participate in potential price increases. As ~~of October 31, 2017, Encana’s 2017 commodity price mitigation program covers about 70 percent~~at June 30, 2018, the Company has hedged approximately 128 Mbbls/d of expected ~~total~~oil and condensate production and 1,084 MMcf/d of expected natural gas production for the remainder of 2018. Additional information on Encana’s hedging program can be found in Note 19 to the ~~year.~~Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Markets for crude oil and natural gas are exposed to different price risks. While the market price for crude oil tends to move in the same direction as the global market, the Permian Basin is experiencing wider differentials due to temporary local export capacity constraints. Natural gas prices may vary between geographic regions depending on local supply and demand conditions. Encana proactively utilizes transportation contracts to diversify the Company’s downstream markets and reduce significant exposure to any given market. Through a combination of derivative financial instruments and transportation capacity, Encana has mitigated the majority of its exposure to Midland and AECO pricing in 2018 and 2019. In addition, Encana continues to seek new markets to yield higher returns.

Capital Investment

Encana is on track to meet its full year capital investment guidance of ~~$1.6~~$1.8 billion to ~~$1.8~~$1.9 billion. During the first ~~nine~~six months of ~~2017,~~2018, the Company spent ~~$1,287 million,~~$1.1 billion, of which ~~96 percent~~$488 million was ~~invested in the Core Assets with 55 percent~~ directed to Permian where the Company has drilled 9455 net ~~wells.~~ wells and $325 million was directed to Montney with 81 net wells drilled. Capital investment in Permian is expected to be optimized by Encana’s cube development approach to maximize returns and recovery. Capital investment in Montney is expected to be allocated to both Cutbank Ridge and Pipestone with a focus on growing condensate volumes. The remainder of the capital investment was primarily directed to Eagle Ford and Duvernay and is expected to optimize production and margins.

Encana continually strives to improve well performance by lowering drilling and completion costs through innovative ~~techniques such as the~~techniques. Encana's large-scale cube development model ~~characterized as a~~utilizes multi-well ~~pad centralized development on a~~pads and advanced completion designs to access stacked pay ~~resource. This approach, which is currently being applied in Permian~~resource to maximize returns and ~~Montney, is helping to boost productivity and enhance~~resource recovery from ~~reservoirs~~its reservoirs. The impact of Encana’s disciplined capital program and continuous innovation create flexibility and opportunity to grow cash flows and production volumes going forward.

Production

As part of the Company’s long-term growth strategy, Encana has significantly shifted its production mix to a more balanced portfolio in ~~those assets.~~

~~Production~~

the recent years, thereby reducing the extent of exposure to market volatility of a particular commodity. During the first ~~nine~~six months of ~~2017,~~2018, average liquids production volumes were ~~121.2~~150.3 Mbbls/d and average natural gas production volumes were 1,085 MMcf/d. The Company expects to deliver substantial liquids growth for the remainder of the year. The Company is on track to meet the ~~updated~~full year 2018 guidance ~~range~~ranges for liquids production volumes of ~~127.0~~165.0 Mbbls/d to ~~132.0~~175.0 Mbbls/d and natural gas production volumes of 1,150 MMcf/d to 1,250 MMcf/d by year end as a result of ~~expected fourth~~the Company’s growth plans for Montney. Encana’s growth plans for Montney are supported by third party processing plants commissioned in 2017 and the second quarter ~~growth in Montney liquids volumes from new facilities in the play~~of 2018, 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 percentplanned completion of the ~~Company’s total production volumes, with~~Pipestone liquids hub in the ~~Core Assets contributing 114.8 Mbbls/d or 95 percent.~~second half of 2018.

Operating Expenses

~~To date, efficiency~~Efficiency improvements and lower service costs ~~have been~~are expected to be maintained through the support of the Company’s culture of innovation and its focus on continuous improvement in operational execution. As activity in the ~~Company continues~~industry accelerates, Encana expects to ~~benefit from transportation contract renegotiations completed~~continue pursuing innovative ways to reduce upstream operating and administrative expenses. Operating costs in ~~2016. The Company reported operating costs for~~ the first ~~nine~~six months of ~~2017 which~~2018 are on track to meet the ~~updated~~ full year ~~2017~~2018 guidance ranges. Transportation and processing expense was ~~$6.52~~$7.58 per BOE, while upstream operating expense and administrative expense, excluding long-term incentive costs, were ~~$3.85~~$3.50 per BOE and ~~$1.58~~$1.43 per BOE, respectively.

Service costs are expected to increase with higher activity in the oil and gas industry and the recovery of liquids prices. Encana continues to offset any inflationary pressures with ~~additional~~ efficiency ~~gains.~~

improvements and effective supply chain management, including favorable price negotiations.

Further information on Encana’s 2018 Corporate Guidance can be accessed on the Company’s website at www.encana.com.
40
Results of Operations

Selected Financial Information

	Three months ended June 30,						Six months ended June 30,
($ millions)	2018			2017 ⁽¹⁾			2018			2017 ⁽¹⁾

Product and Service Revenues
Upstream product revenues	$	984		$	729		$	1,941		$	1,467
Market optimization		291			204			592			390
Service revenues		2			4			4			14
Total Product and Service Revenues		1,277			937			2,537			1,871

Gains (Losses) on Risk Management, Net		(312	)		129			(276	)		467
Sublease Revenues		18			17			35			34
Total Revenues		983			1,083			2,296			2,372

Total Operating Expenses⁽²⁾		1,099			762			2,075			1,562
Operating Income (Loss)		(116	)		321			221			810
Total Other (Income) Expenses		105			(6	)		282			49
Net Earnings (Loss) Before Income Tax		(221	)		327			(61	)		761
Income Tax Expense (Recovery)		(70	)		(4	)		(61	)		(1	)

Net Earnings (Loss)	$	(151	)	$	331		$	-		$	762

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.

(1)	2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”, as described in Note 2 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

(2)	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~~NGLs 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.~~as well as other downstream natural gas benchmarks, including Dawn. The USA Operations realized prices generally reflect WTI and NYMEX benchmark ~~prices.~~prices, as well as other downstream oil benchmarks. The other downstream benchmarks reflect the diversification of the Company’s markets. Realized NGL prices are significantly influenced by oil benchmark prices and the NGL production mix. Recent trends in benchmark prices relevant to Encana are shown in the table below.

Benchmark Prices

	Three months ended June 30,				Six months ended June 30,
(average for the period)	2018		2017		2018		2017

Oil & NGLs
WTI ($/bbl)	$	67.88	$	48.29	$	65.37	$	50.10
Edmonton Condensate (C$/bbl)	$	88.84	$	64.59	$	84.28	$	66.87

Natural Gas
NYMEX ($/MMBtu)	$	2.80	$	3.18	$	2.90	$	3.25
AECO (C$/Mcf)	$	1.03	$	2.77	$	1.44	$	2.86
Dawn (C$/MMBtu)	$	3.60	$	4.17	$	3.71	$	4.20

     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 June 30,								Six months ended June 30,
	Production Volumes ⁽¹⁾				Realized Prices ⁽²⁾				Production Volumes ⁽¹⁾				Realized Prices ⁽²⁾
	2018		2017		2018		2017		2018		2017		2018		2017

Oil (Mbbls/d, $/bbl)
Canadian Operations		0.4		0.4	$	58.13	$	40.23		0.4		0.4	$	56.87	$	41.77
USA Operations		84.2		77.0		66.57		46.14		83.4		72.0		64.97		47.75
Total		84.6		77.4		66.52		46.11		83.8		72.4		64.93		47.72

NGLs – Plant Condensate (Mbbls/d, $/bbl)
Canadian Operations		29.9		20.5		67.55		46.94		28.7		19.6		64.48		48.53
USA Operations		3.8		2.3		57.20		41.07		3.2		2.1		55.05		41.86
Total		33.7		22.8		66.38		46.34		31.9		21.7		63.51		47.89

NGLs – Other (Mbbls/d, $/bbl)
Canadian Operations		12.5		4.7		26.27		19.10		11.5		4.9		27.99		20.91
USA Operations		24.5		20.0		22.37		16.06		23.1		19.0		21.51		17.97
Total		37.0		24.7		23.69		16.65		34.6		23.9		23.66		18.57

Total NGLs (Mbbls/d, $/bbl)
Canadian Operations		42.4		25.2		55.35		41.73		40.2		24.5		54.03		43.01
USA Operations		28.3		22.3		27.08		18.68		26.3		21.1		25.67		20.34
Total		70.7		47.5		44.01		30.93		66.5		45.6		42.79		32.54

Total Oil & NGLs (Mbbls/d, $/bbl)
Canadian Operations		42.8		25.6		55.38		41.71		40.6		24.9		54.06		43.00
USA Operations		112.5		99.3		56.61		40.00		109.7		93.1		55.53		41.55
Total		155.3		124.9		56.27		40.35		150.3		118.0		55.14		41.86

Natural Gas (MMcf/d, $/Mcf)
Canadian Operations		949		785		1.84		2.33		942		835		2.16		2.43
USA Operations		146		361		2.07		3.09		143		359		2.29		3.16
Total		1,095		1,146		1.87		2.57		1,085		1,194		2.17		2.65

Total Production (MBOE/d, $/BOE)
Canadian Operations		200.9		156.6		20.50		18.52		197.6		164.1		21.37		18.89
USA Operations		137.0		159.4		48.72		31.92		133.6		152.8		48.08		32.71
Total		337.9		316.0		31.93		25.29		331.2		316.9		32.14		25.55

Production Mix (%)
Oil & Plant Condensate		35		32						35		30
NGLs – Other		11		8						10		7
Total Oil & NGLs		46		40						45		37
Natural Gas		54		60						55		63

Core Assets Production
Oil (Mbbls/d)		82.4		73.6						81.4		67.9

NGLs – Plant Condensate (Mbbls/d)		33.6		22.4						31.8		21.1
NGLs – Other (Mbbls/d)		35.8		22.8						33.5		22.0
Total NGLs (Mbbls/d)		69.4		45.2						65.3		43.1

Total Oil & NGLs (Mbbls/d)		151.8		118.8						146.7		111.0

Natural Gas (MMcf/d)		1,027		768						1,013		786

Total Production (MBOE/d)		322.9		246.5						315.3		242.0

% of Total Encana Production		96		78						95		76

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)

~~(1)~~

Average daily.

(2)

~~(2)~~

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

Upstream Product Revenues


	Three months ended September 30,										Nine months ended September 30,												Three months ended June 30,									Six months ended June 30,
					Natural												Natural
($ millions)	Oil		NGLs ⁽¹⁾		Gas			Total			Oil			NGLs ⁽¹⁾			Gas			Total			Oil		NGLs ⁽¹⁾		Natural Gas ⁽²⁾			Total		Oil		NGLs ⁽¹⁾		Natural Gas ⁽²⁾			Total

2016 Product Revenues	$	266	$	114	$	261		$	641		$	761		$	303		$	674		$	1,738
2017 Upstream Product Revenues																							$	325	$	135	$	268		$	728	$	625	$	269	$	572		$	1,466
Increase (decrease) due to:
Sales prices		28		32		(4	)		56			211			137			229			577			158		72		(55	)		175		262		103		(61	)		304
Production volumes		23		10		(84	)		(51	)		(30	)		(15	)		(158	)		(203	)		28		76		(26	)		78		98		142		(83	)		157
2017 Product Revenues	$	317	$	156	$	173		$	646		$	942		$	425		$	745		$	2,112
(1) Includes plant condensate.
2018 Upstream Product Revenues																							$	511	$	283	$	187		$	981	$	985	$	514	$	428		$	1,927

(1)	Includes plant condensate.

(2)	Natural gas revenues for the second quarter and the first six months of 2018 exclude a royalty adjustment with no associated production volumes of $3 million and $14 million, respectively (2017 - $1 million and $1 million, respectively).

Oil Revenues

Three months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Oil revenues increased ~~$51~~$186 million compared to the second quarter of 2017 primarily due to:

Higher average realized oil prices of $20.41 per bbl, or 44 percent, increased revenues by $158 million. The increase reflected a higher WTI benchmark price which was up 41 percent and exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and

Higher average oil production volumes of 7.2 Mbbls/d increased revenues by $28 million. Higher volumes were primarily due to successful drilling program in Permian (17.9 Mbbls/d), partially offset by natural declines in Eagle Ford (7.9 Mbbls/d) andasset sales (1.1 Mbbls/d), which mainly include the Piceance natural gas assets in the third quarter of ~~2016 primarily due to:~~2017 and the Tuscaloosa Marine Shale assets in the second quarter of 2017.

●

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~~Six months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Oil revenues increased ~~$181~~$360 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher average realized oil prices of $17.21 per bbl, or 36 percent, increased revenues by $262 million. The increase reflected a higher WTI benchmark price which was up 30 percent and exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets. The increase was also due to improved regional pricing; and

●

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;

Higher average oil production volumes of 11.4 Mbbls/d increased revenues by $98 million. Higher volumes were primarily due to successful drilling program in Permian (18.6 Mbbls/d), partially offset ~~by:~~by natural declines in Eagle Ford (4.2 Mbbls/d) andasset sales (1.7 Mbbls/d), which mainly include the Tuscaloosa Marine Shale assets in the second quarter of 2017 and thePiceance natural gas assets in the third quarter of 2017.

●

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~~June 30, 2018 versus June 30, 2017

NGL revenues increased $148 million compared to the second quarter of 2017 primarily due to:

Higher average realized NGL prices of $13.08 per bbl, or 42 percent, increased revenues by $72 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 41 percent and 38 percent, respectively, as well as improved regional pricing; and

Higher average NGL production volumes of 23.2 Mbbls/d increased revenues by $76 million. Higher volumes were primarily due to successful drilling programs in Montney and Permian (31.6 Mbbls/d), partially offset by increased downtime resulting from scheduled plant maintenance for processing liquids rich volumes in Montney (3.6 Mbbls/d) and natural declines in Duvernay (2.6 Mbbls/d).

Six months ended June 30, 2018 versus ~~September~~June 30, ~~2016~~2017

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~~$245 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher average realized NGL prices of $10.25 per bbl, or 31 percent, increased revenues by $103 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 30 percent and 26 percent, respectively, as well as improved regional pricing; and

●

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;

Higher average NGL production volumes of 20.9 Mbbls/d increased revenues by $142 million. Higher volumes were primarily due to successful drilling programs in Montney and Permian (26.5 Mbbls/d), partially offset ~~by:~~by increased downtime resulting from scheduled plant maintenance for processing liquids rich volumes in Montney (1.7 Mbbls/d), natural declines in Duvernay (1.7 Mbbls/d) and asset sales (1.4 Mbbls/d), which mainly include the Piceance natural gas assets in the third quarter of 2017.

●

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~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Natural gas revenues decreased ~~$88~~$81 million compared to the second quarter of 2017 primarily due to:

Lower average realized natural gas prices of $0.70 per Mcf, or 27 percent, decreased revenues by $55 million. The decrease reflected lower NYMEX and AECO benchmark prices which were down 12 percent and 63 percent, respectively, partially offset by exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and

Lower average natural gas production volumes of 51 MMcf/d decreased revenues by $26 million. Lower volumes were primarily due to asset sales (294 MMcf/d), which mainly include the Piceance natural gas assets in the third quarter of ~~2016 primarily due to:~~2017 and certain assets in Wheatland in the fourth quarter of 2017, lower activity in Other Upstream Operations (23 MMcf/d) and natural declines in Duvernay (10 MMcf/d), partially offset by successful drilling programs in Montney and Permian (258 MMcf/d), and decreased downtime resulting from scheduled plant maintenance in Montney (28 MMcf/d).

●

~~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~~Six months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Natural gas revenues ~~increased $71~~decreased $144 million compared to the first ~~nine~~six months of ~~2016~~2017 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;

Lower average realized natural gas prices of $0.48 per Mcf, or 18 percent, decreased revenues by $61 million. The decrease reflected lower NYMEX and AECO benchmark prices which were down 11 percent and 50 percent, respectively, partially offset ~~by:~~by exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and

Lower average natural gas production volumes of 109 MMcf/d decreased revenues by $83 million. Lower volumes were primarily due to asset sales (299 MMcf/d), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017, and lower activity in Other Upstream Operations (46 MMcf/d), partially offset by successful drilling programs in Montney and Permian (228 MMcf/d) and decreased downtime resulting from scheduled plant maintenance in Montney (14 MMcf/d).

●

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~~June 30, ~~2017~~2018 can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q.

The following ~~table provides~~tables provide 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

	Three months ended June 30,					Six months ended June 30,
($ millions)	2018			2017		2018			2017

Realized Gains (Losses) on Risk Management
Commodity Price ⁽¹⁾
Oil	$	(65	)	$	16	$	(121	)	$	16
NGLs ⁽²⁾		(37	)		2		(58	)		1
Natural Gas		116			-		160			(25	)
Other ⁽³⁾		-			1		1			3
Total		14			19		(18	)		(5	)

Unrealized Gains (Losses) on Risk Management		(326	)		110		(258	)		472
Total Gains (Losses) on Risk Management, Net	$	(312	)	$	129	$	(276	)	$	467

	Three months ended June 30,						Six months ended June 30,
(Per-unit)	2018			2017			2018			2017

Realized Gains (Losses) on Risk Management
Commodity Price
Oil ($/bbl)	$	(8.52	)	$	2.16		$	(8.04	)	$	1.19
NGLs ($/bbl) ⁽¹⁾	$	(5.63	)	$	0.73		$	(4.76	)	$	0.19
Natural Gas ($/Mcf)	$	1.16		$	(0.01	)	$	0.81		$	(0.12	)
Total ($/BOE)	$	0.44		$	0.62		$	(0.32	)	$	(0.14	)

(1)	~~(1)~~ Includes realized gains and losses related to the Canadian and USA Operations.

(2)	Includes plant condensate.

(3)

~~(2)~~

Other primarily includes realized gains or losses from Market Optimization and other derivative contracts with no associated production volumes.

Encana recognizes fair value changes from its risk management activities each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationship between contract prices and the associated forward curves. Realized gains or losses on risk management activities related to commodity price mitigation are

included in the Canadian Operations, USA Operations and Market Optimization revenues as the contracts are cash ~~settled.~~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,				Three months ended June 30,				Six months ended June 30,
($ millions)	2017		2016		2017		2016		2018		2017		2018		2017

Market Optimization	$	224	$	215	$	614	$	393	$	291	$	204	$	592	$	390

Three months ended ~~September~~June 30, 2018 versus June 30, 2017

Market Optimization revenues increased $87 million compared to the second quarter of 2017 primarily due to:

Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($175 million), partially offset by lower natural gas commodity prices ($88 million).

Six months ended June 30, 2018 versus ~~September~~June 30, ~~2016~~2017

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~~$202 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($343 million), partially offset by lower natural gas commodity prices ($141 million).

●

~~Higher commodity prices ($160 million) and higher sales of third-party purchased volumes used for optimization activities ($61 million).~~

~~Other~~Sublease Revenues

~~Other Revenues~~Sublease revenues primarily ~~includes~~include 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.~~segment. Further information on The Bow office sublease can be found in Note 1011 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-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 natural 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,				Three months ended June 30,				Six months ended June 30,
($ millions)	2017		2016		2017		2016		2018		2017		2018		2017

Canadian Operations	$	6	$	5	$	16	$	17	$	4	$	5	$	8	$	10
USA Operations		21		15		64		56		31		19		56		43
Total	$	27	$	20	$	80	$	73	$	35	$	24	$	64	$	53

	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 June 30,				Six months ended June 30,
($/BOE)	2018		2017		2018		2017

Canadian Operations	$	0.21	$	0.39	$	0.22	$	0.34
USA Operations	$	2.48	$	1.29	$	2.31	$	1.55
Total	$	1.13	$	0.85	$	1.06	$	0.93

Three months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Production, mineral and other taxes increased $7$11 million compared to the second quarter of 2017 primarily due to:

Higher liquids prices and production volumes in Permian ($8 million) and the recovery of certain production taxes in the USA Operations in 2017 ($7 million);

partially offset by:

Asset sales ($5 million), which mainly include the Piceance natural gas assets in the third quarter of ~~2016 primarily due to:~~2017 and certain assets in Wheatland in the fourth quarter of 2017.

●

~~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~~Six months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Production, mineral and other taxes increased $7$11 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher liquids prices and production volumes in Permian ($15 million) and the recovery of certain production taxes in the USA Operations in 2017 ($3 million).

●

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

partially offset ~~by:~~by:

Asset sales ($10 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.

●

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~~sales- quality product.


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
($ millions)	2017		2016		2017		2016		2018		2017		2018		2017

Canadian Operations	$	138	$	136	$	403	$	440	$	207	$	133	$	397	$	265
USA Operations		31		43		141		214		31		51		58		110
Upstream Transportation and Processing		169		179		544		654		238		184		455		375

Market Optimization		30		22		73		65		34		22		66		43
Corporate & Other		-		1		-		(4)		-		-		-		-
Total	$	199	$	202	$	617	$	715	$	272	$	206	$	521	$	418

	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 June 30,

Six months ended June 30,

($/BOE)

2018

2017

2018

2017

Canadian Operations

$
11.29

$
9.30

$
11.09

$
8.91

USA Operations

$
2.51

$
3.54

$
2.39

$
3.97

Upstream Transportation and Processing

$
7.73

$
6.39

$
7.58

$
6.53

Three months ended ~~September~~June 30, 2018 versus June 30, 2017

Transportation and processing expense increased $66 million compared to the second quarter of 2017 primarily due to:

Higher downstream processing and transportation costs due to higher volumes primarily in Montney and Permian and costs relating to the diversification of the Company’s downstream markets ($46 million), higher volumes and gathering and processing fees in Montney and Permian ($42 million) and the higher U.S./Canadian dollar exchange rate ($6 million);

partially offset by:

Asset sales ($30 million), which mainly include the Piceance natural gas assets in the third quarter of 2017.

Six months ended June 30, 2018 versus ~~September~~June 30, ~~2016~~2017

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~~increased $103 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher downstream processing and transportation costs due to higher volumes primarily in Montney and Permian and costs relating to the diversification of the Company’s downstream markets ($87 million), higher volumes and gathering and processing fees in Montney and Permian ($74 million) and the higher U.S./Canadian dollar exchange rate ($12 million);

●

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:

Asset sales ($61 million), which mainly include the Piceance natural gas assets in the third quarter of 2017.

●

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


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
($ millions)	2017		2016		2017		2016		2018		2017		2018		2017

Canadian Operations	$	36	$	38	$	89	$	115	$	35	$	22	$	64	$	53
USA Operations		81		93		252		293		84		84		158		171
Upstream Operating Expense		117		131		341		408		119		106		222		224

Market Optimization		11		11		23		25		13		3		17		12
Corporate & Other		4		3		13		13		5		4		9		9
Total	$	132	$	145	$	377	$	446	$	137	$	113	$	248	$	245

	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

	Three months ended June 30,				Six months ended June 30,
($/BOE)	2018		2017		2018		2017

Canadian Operations	$	1.89	$	1.52	$	1.75	$	1.73
USA Operations	$	6.75	$	5.60	$	6.52	$	5.99
Upstream Operating Expense ⁽¹⁾	$	3.86	$	3.58	$	3.67	$	3.78

(1)

~~(1)~~

Upstream Operating Expense per BOE for the ~~third~~second quarter and ~~the~~ first ~~nine~~six months of ~~2017~~2018 includes long-term incentive costs of ~~$0.45/~~$0.46/BOE and ~~$0.13/~~$0.17/BOE, respectively ~~(2016~~(2017 - ~~$0.44/~~recovery of long-term incentive costs of $0.18/BOE and ~~$0.24/~~$0.01/BOE, respectively).

Three months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Operating expense ~~decreased $13~~increased $24 million compared to the ~~third~~second quarter of ~~2016~~2017 primarily due to:

Long-term incentive costs resulting from the increase in Encana’s share price in the second quarter of 2018 ($30 million) and higher activity in Permian and Montney ($11 million).

●

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~~Asset sales ($15 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.

Six months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Operating expense ~~decreased $69~~increased $3 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher activity in Permian and Montney ($23 million) and long-term incentive costs resulting from the increase in Encana’s share price in the first six months of 2018 ($16 million).

●

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:

Asset sales ($33 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.

●

~~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 Form10-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,				Three months ended June 30,				Six months ended June 30,
($ millions)	2017		2016		2017		2016		2018		2017		2018		2017

Market Optimization	$	202	$	197	$	565	$	349	$	248	$	192	$	521	$	363

Three months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Purchased product expense increased $5$56 million compared to the ~~third~~second quarter of ~~2016~~2017 primarily due to:

Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($159 million), partially offset by lower natural gas commodity prices ($103 million).

●

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

~~Nine~~Six months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Purchased product expense increased ~~$216~~$158 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($321 million), partially offset by lower natural gas commodity prices ($163 million).

●

~~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 theunit-of-production method based on proved reserves as discussed in Note 1 to the Consolidated Financial Statements included in Item 8 of the ~~2016~~2017 Annual Report on Form~~10-K.~~ 10-K. Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates as well as fluctuations in12-month average trailing prices which affect proved reserves volumes. ~~For additional~~Additional information oncan be found in the Critical Accounting Estimates ~~refer to~~section of the MD&A included in Item 7 of the ~~2016~~2017 Annual Report on Form10-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,				Three months ended June 30,				Six months ended June 30,
($ millions)	2017		2016		2017		2016		2018		2017		2018		2017

Canadian Operations	$	53	$	54	$	170	$	203	$	85	$	53	$	162	$	117
USA Operations		139		112		368		414		202		123		387		229
Upstream DD&A		192		166		538		617		287		176		549		346

Market Optimization		1		-		1		-		1		-		1		-
Corporate & Other		17		18		51		58		12		17		25		34
Total	$	210	$	184	$	590	$	675	$	300	$	193	$	575	$	380

	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 June 30,				Six months ended June 30,
($/BOE)	2018		2017		2018		2017

Canadian Operations	$	4.67	$	3.72	$	4.53	$	3.92
USA Operations	$	16.15	$	8.47	$	16.00	$	8.29
Upstream DD&A	$	9.33	$	6.12	$	9.16	$	6.02

Three months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

DD&A increased ~~$26~~$107 million compared to the ~~third~~second quarter of ~~2016~~2017 primarily due to:

Higher depletion rates primarily in the USA Operations ($109 million) and higher volumes in the Canadian Operations ($13 million);

●

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

partially offset by:

Lower volumes in the USA Operations ($14 million);

The depletion ~~rate~~rates in the Canadian and USA Operations increased ~~$2.05~~$0.95 per BOE and $7.68 per BOE, respectively, compared to the ~~third~~second quarter of ~~2016~~2017 primarily due to:

●

~~Lower~~Higher capital spending and changes in Encana’s development plans as a result of the increased capital program for 2018 and 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~~third quarter of 2017.

Six months ended June 30, 2018 versus June 30, 2017

DD&A increased $195 million compared to the first six months of 2017 primarily due to:

Higher depletion rates primarily in the USA Operations ($199 million) and higher volumes in the Canadian Operations ($20 million);

partially offset by:

Lower volumes in the USA Operations ($22 million);

The depletion rates in the Canadian and USA Operations increased $0.61 per BOE and $7.71 per BOE, respectively, compared to the first six months of 2017 primarily due to:

Higher capital spending and changes in Encana’s development plans as a ~~gain on divestiture, whereas proceeds~~result of the increased capital program for 2018 and lower reserve volumes from the sale of the ~~DJ Basin~~Piceance natural gas 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.2017.

~~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 the12-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.~~

~~The12-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 discountedafter-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,				Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017

Administrative ($ millions)	$	86	$	91	$	168	$	231	$	99	$	24	$	130	$	82
Administrative ($/BOE)	$	3.31	$	2.94	$	2.02	$	2.33
Administrative ($/BOE) ⁽¹⁾									$	3.20	$	0.82	$	2.17	$	1.43

(1)	Administrative expense per BOE for the second quarter and first six months of 2018 includes long-term incentive costs of $1.84/BOE and $0.74/BOE, respectively (2017 - recovery of long-term incentive costs of $0.79/BOE and $0.13/BOE, respectively).

Three months ended June 30, 2018 versus June 30, 2017

Administrative expense in the ~~third~~second quarter of 2018 increased $75 million compared to the second 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~~second quarter of ~~2017~~2018 ($878 million). ~~Administrative expense per BOE for the third quarter of~~

Six months ended June 30, 2018 versus June 30, 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~~six months of 2018 increased $48 million compared to the first six 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~~increase in Encana’s share price in the first ~~nine~~six months of ~~2017~~2018 ($2251 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 June 30,						Six months ended June 30,
($ millions)	2018			2017			2018			2017

Interest	$	81		$	79		$	173		$	167
Foreign exchange (gain) loss, net		25			(58	)		116			(84	)
(Gain) loss on divestitures, net		(1	)		-			(4	)		1
Other (gains) losses, net		-			(27	)		(3	)		(35	)
Total Other (Income) Expenses	$	105		$	(6	)	$	282		$	49

   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~~ Further details on changes 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 Note 5 to the ~~Liquidity and Capital Resources section~~Consolidated Financial Statements included in Part I, Item 1 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.Quarterly Report on Form 10-Q.

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~~Further details on changes 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~~or 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 theout-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 Form10-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~~foreign exchange rates and the effects of foreign exchange rate changes can be found in ~~Note 4 to the Consolidated Financial Statements included in Part I,~~ Item 13 of this Quarterly Report on Form10-Q.

~~Gain~~In the second quarter of 2018, Encana recorded a net foreign exchange loss of $25 million compared to a net gain of $58 million in 2017. The change was primarily due to unrealized foreign exchange losses on ~~divestitures~~the translation of U.S. dollar financing debt issued from Canada compared to gains in 2017 ($135 million) and on the ~~third quarter and~~translation of U.S. dollar risk management contracts issued from Canada compared to gains in 2017 ($29 million), partially offset by unrealized foreign exchange gains on the translation of intercompany notes compared to losses in 2017 ($72 million).

In the first ~~nine~~six months of ~~2017~~2018, Encana recorded a net foreign exchange loss of $116 million compared to a net gain of $84 million in 2017. The change was primarily ~~includes the before tax gain~~due to unrealized foreign exchange losses on the ~~sale~~translation of ~~the Piceance natural gas assets. Gain on divestitures~~U.S. dollar financing debt issued from Canada compared to gains in ~~the third quarter~~2017 ($290 million) and ~~first nine months of 2016 primarily includes the before tax gain~~ on the ~~sale~~translation of ~~the Gordondale assets~~U.S. dollar risk management contracts issued from Canada compared to gains in ~~the third quarter of 2016. Further information~~2017 ($42 million), partially offset by unrealized foreign exchange gains on the ~~divestitures can be found~~translation of intercompany notes compared to losses in 2017 ($54 million) and realized foreign exchange gains on the ~~Liquidity and Capital Resources section~~settlement of ~~this MD&A.~~intercompany notes compared to losses in 2017 ($49 million).

Other (Gains) Losses, Net

Other (gains) losses, net primarily includes othernon-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 second quarter and first ~~nine~~six months of 2017 primarily includes interest received of $26 million and $33 million, respectively, 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 June 30,					Six months ended June 30,
($ millions)	2018		2017			2018		2017

Current Income Tax Expense (Recovery)	$	(64)	$	(18	)	$	(61)	$	(57	)
Deferred Income Tax Expense (Recovery)		(6)		14			-		56
Income Tax Expense (Recovery)	$	(70)	$	(4	)	$	(61)	$	(1	)

Effective Tax Rate	31.7%		(1.2%		)	100.0%		(0.1%		)

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~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

In the ~~third~~second quarter of ~~2017,~~2018, Encana recorded a higher current income tax recovery compared to 2017. The higher income tax recovery was primarily due to the resolution of certain tax items relating to prior taxation years.

Deferred income tax in the second quarter was a recovery compared to an expense in 2017 primarily due to:

Net loss before income tax in 2018 compared to net earnings before income tax in 2017; and

A reduction in the U.S. federal corporate tax rate to 21 percent from 35 percent resulting from U.S. Tax Reform.

Six months ended June 30, 2018 versus June 30, 2017

In the first six months of 2018, Encana recorded a lower deferred income tax expense compared to ~~2016~~2017 primarily due to a ~~higher deferred tax expense as a result of changes in the estimated annual effective~~net loss before 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~~in 2018 compared to net earnings before income tax ~~expense compared~~in 2017 and U.S. Tax Reform, both as discussed above.

There has been no change in 2018 to ~~an income~~the provisional tax ~~recovery~~adjustment recognized in ~~2016 primarily~~December 2017 resulting from the re‑measurement of the Company’s tax position due to ~~operating income~~a reduction of the U.S federal corporate tax rate under U.S. Tax Reform. Additional information on U.S. Tax Reform can be found in ~~2017 compared to an operating loss in 2016.~~

~~The current income tax recovery in the first nine months of 2017 was primarily due~~Note 6 to the ~~successful resolution~~Consolidated Financial Statements included in Item 8 of ~~certain tax items previously assessed by~~ the ~~tax authorities relating to prior taxation years.~~

2017 Annual Report on Form 10-K.

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 toyear-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, the effect of legislative changes including U.S. Tax Reform, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. ~~These items resulted in an~~The Company’s effective tax rate was 31.7 percent for the ~~third~~second quarter and 100 percent for the first six months of ~~2017 that is~~2018, which are higher than the Canadian statutory rate of 27 percent ~~and an effective~~primarily due to the impact of the foreign jurisdictional tax ~~rate for the first nine months of 2017 that is below~~rates relative to the Canadian statutory ~~rate. The effective~~ tax rate ~~for~~applied to jurisdictional earnings as well as the ~~first nine months of 2017 was also impacted by the tax reassessments~~current year items discussed above.

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

~~Liquidity and Capital~~

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.~~or to manage its capital structure as discussed below. At ~~September~~June 30, ~~2017, $384~~2018, $154 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, purchasing shares for cancellation through a NCIB, 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

	As at June 30,
($ millions, except as indicated)	2018		2017

Cash and Cash Equivalents	$	336	$	395
Available Credit Facility – Encana ⁽¹⁾		2,500		3,000
Available Credit Facility – U.S. Subsidiary ⁽¹⁾		1,500		1,500
Total Liquidity	$	4,336	$	4,895

Long-Term Debt, including current portion	$	4,198	$	4,198
Total Shareholders’ Equity	$	6,497	$	6,783

Debt to Capitalization (%) ⁽²⁾		39		38
Debt to Adjusted Capitalization (%) ⁽³⁾		23		22

(1)

~~(1)~~

Collectively, the “Credit Facilities”.

(2)

~~(2)~~

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

(3)

~~(3)~~

Anon-GAAP measure which is defined in theNon-GAAP Measures section of this MD&A.

In the first quarter of 2018, the Company amended the capacity of its Encana Credit Facility from $3.0 billion to $2.5 billion and extended the maturity for both Credit Facilities to July 2022.

Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is anon-GAAP measure defined in theNon-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 1312 to the Consolidated Financial Statements included in Item 8 of the ~~2016~~2017 Annual Report on Form10-K.

Sources and Uses of Cash

In the ~~third~~second quarter and first ~~nine~~six months of ~~2017,~~2018, 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,					Three months ended June 30,						Six months ended June 30,
($ millions)		Activity Type		2017		2016		2017		2016		Activity Type	2018			2017			2018			2017

Sources of Cash and Cash Equivalents

Cash from operating activities			Operating	$	357	$	186	$	681	$	426	Operating	$	475		$	218		$	856		$	324

Proceeds from divestitures			Investing		625		1,107		710		1,113	Investing		46			82			65			85

Issuance of common shares			Financing		-		981		-		981

Other			Investing		14		-		93		-	Investing		105			24			80			79
					996		2,274		1,484		2,520			626			324			1,001			488

Uses of Cash and Cash Equivalents

Capital expenditures			Investing		473		205		1,287		779	Investing		595			415			1,103			814

Acquisitions			Investing		2		67		50		69	Investing		-			2			2			48

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

Repayment of long-term debt			Financing		-		-		-		400

Purchase of common shares												Financing		89			-			200			-
Dividends on common shares			Financing		14		13		43		37	Financing		14			14			29			29

Other			Investing/Financing		21		22		61		98	Financing		23			24			45			40
					510		1,800		1,441		2,033			721			455			1,379			931
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency														(2	)		3			(5	)		4

Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency					8		(1)		12		8
Increase (Decrease) in Cash and Cash Equivalents	Increase (Decrease) in Cash and Cash Equivalents			$	494	$	473	$	55	$	495		$	(97	)	$	(128	)	$	(383	)	$	(439	)

Operating Activities

Cash from operating activities ~~can be significantly impacted by fluctuations~~ in the second quarter and first six months of 2018 was $475 million and $856 million, respectively, and was primarily a reflection of recovering 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,~~volumes, the Company’s efforts in maintaining cost efficiencies achieved in ~~2016, the effects of the commodity price mitigation program,~~previous years and 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 innon-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 Form10-Q. Encana expects it will continue to meet the payment terms of its suppliers.

Non-GAAP Cash Flow in the ~~third~~second quarter and first ~~nine~~six months of ~~2017~~2018 was ~~$270~~$586 million and ~~$899~~$986 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 innon-cash~~ ~~working capital as disclosed in theNon-GAAP~~ ~~Measures section of this MD&A.~~

Three months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Net cash from operating activities increased ~~$171~~$257 million compared to the ~~third~~second quarter of ~~2016~~2017 primarily due to:

Higher realized commodity prices ($175 million), higher production volumes ($78 million), higher current tax recovery ($46 million) and changes in non-cash working capital ($23 million);

●

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

partially offset by:

●

~~Lower production volumes ($51 million).~~

~~Nine~~Higher transportation and processing expense ($66 million) and lower interest income recorded in other gains ($25million).

Six months ended ~~September~~June 30, ~~2017~~2018 versus ~~September~~June 30, ~~2016~~2017

Net cash from operating activities increased ~~$255~~$532 million compared to the first ~~nine~~six months of ~~2016~~2017 primarily due to:

Higher realized commodity prices ($304million), changes in non-cash working capital ($175million) and higher production volumes ($157 million);

●

~~Higher realized commodity prices ($577 million), lower transportation and processing expense ($98 million), lower operating expense, excludingnon-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:

Higher transportation and processing expense ($103million) and lower interest income recorded in other gains ($31million).

●

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

Investing Activities

~~Net cash~~Cash used in investing activities in the first ~~nine~~six months of ~~2017~~2018 was ~~$534~~$960 million primarily due to capital ~~expenditures, partially offset by proceeds from divestitures.~~expenditures. Capital expenditures in the first ~~nine~~six months of ~~2017~~2018 increased ~~$508~~$289 million compared to ~~2016~~2017 due to an increase in the Company’s capital program for ~~2017. Capital expenditures in the Core Assets totaled $1,240 million, representing 96 percent of total capital expenditures, and increased $493 million compared to 2016,~~2018. This increase was primarily in ~~Permian~~Montney ($~~285 million), Eagle Ford ($90~~202 million) and ~~Montney~~Permian ($~~130~~63 million). Capital expenditures exceeded cash from operating activities by ~~$606~~$247 million and the difference was funded using cash on hand and proceeds from divestitures.

Divestitures in the first ~~nine~~six months of ~~2017~~2018 were ~~$710~~$65 million, which primarily included the sale of the ~~Piceance natural gas~~Pipestone midstream assets in ~~northwestern Colorado, comprising approximately 550,000 net acres~~Alberta. Divestitures in the first six months of ~~leasehold and 3,100 operated wells. Divestitures also~~2017 were $85 million, which primarily included the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana, ~~and~~as well as 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~~six months of 2018 and 2017 ~~and 2016~~ were ~~$50~~$2 million and ~~$69~~$48 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 48 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q.

Financing Activities

Net cash used in financing activities in the first ~~nine~~six months of ~~2017 decreased $51~~2018 increased $205 million ~~from 2016~~compared to the first six months of 2017. The change was primarily due to the purchase of common shares under a ~~net repayment of revolving long-term debt ($650 million) and a repayment of long-term debt ($400 million)~~NCIB in the first ~~nine~~six months of ~~2016, partially offset by the issuance of common shares in the first nine months of 2016~~2018 ($~~981~~200 million). as discussed below.

Encana’s long-term debt, excluding the current portion, totaled ~~$4,197~~$3,698 million at ~~September~~June 30, ~~2017~~2018 and ~~$4,198~~$4,197 million at December 31, ~~2016.~~2017. The current portion of long-term debt outstanding was $500 million at June 30, 2018. There was no current portion of long-term debt outstanding at ~~September 30, 2017 or~~ December 31, ~~2016. At September 30, 2017,~~2017. Encana has no long-term debt maturities until May 2019 and, as at June 30, 2018, 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.~~2022. The Credit Facilities provide financial flexibility and allow the Company to fund its operations, development activities or capital program. At ~~September~~June 30, ~~2017,~~2018, Encana had no outstanding balance under the Credit ~~Facilities.~~Facilities and $147 million in undrawn letters of credit issued in the normal course of business primarily as collateral security, to support future abandonment liabilities and for transportation arrangements.

Dividends

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

	Three months ended June 30,				Six months ended June 30,
($ millions, except as indicated)	2018		2017		2018		2017

Dividend Payments	$	14	$	14	$	29	$	29
Dividend Payments ($/share)	$	0.015	$	0.015	$	0.03	$	0.03

On ~~September 23, 2016, Encana completed~~July 31, 2018, the Board of Directors declared a ~~public offering (the “2016 Share Offering”)~~dividend of ~~107,000,000 common shares of Encana at a price of $9.35~~$0.015 per common share payable on September 28, 2018 to common shareholders of record as of September 14, 2018.

Normal Course Issuer Bid

On February 26, 2018, Encana received approval from the TSX to commence a NCIB that enables the Company to purchase, for ~~gross proceeds~~cancellation, up to 35 million common shares over a 12-month period from February 28, 2018 to February 27, 2019. The number of shares authorized for purchase represents approximately 3.6 percent of Encana’s issued and outstanding common shares as at February 20, 2018. The Company has authorization from its Board to spend up to $400 million on the NCIB. For the second quarter and first six months of 2018, the Company used cash on hand to purchase approximately 6.8 million and 16.8 million common shares, respectively, for total consideration of approximately ~~$1.0 billion ($981~~$89 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~~and $200 million, respectively.

For 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~~NCIB, refer to Note 1213 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-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 onoff-balance sheet arrangements and transactions, refer to theOff-Balance Sheet Arrangements section of the MD&A included in Item 7 of the ~~2016~~2017 Annual Report on Form10-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 Form10-Q.

Non-GAAP Measures

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considerednon-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~~Non-GAAP Cash Flow Margin, ~~and~~ Debt to Adjusted ~~Capitalization.~~Capitalization and Net Debt to Adjusted EBITDA. Management’s use of these measures is discussed further below.

Non-GAAP Cash Flow and ~~Corporate~~Non-GAAP Cash Flow Margin

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

~~Corporate~~Non-GAAP Cash Flow Margin is anon-GAAP measure defined asNon-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,				Three months ended June 30,						Six months ended June 30,
($ millions, except as indicated)	2017		2016		2017		2016		2018			2017			2018			2017

Cash From (Used in) Operating Activities	$	357	$	186	$	681	$	426	$	475		$	218		$	856		$	324

(Add back) deduct:

Net change in other assets and liabilities		(11)		(6)		(27)		(15)		(5	)		(4	)		(16	)		(16	)

Net change innon-cash working capital		98		(60)		(191)		(95)		(106	)		(129	)		(114	)		(289	)

Current tax on sale of assets		-		-		-		-		-			-			-			-

Non-GAAP Cash Flow	$	270	$	252	$	899	$	536	$	586		$	351		$	986		$	629

Production Volumes (MMBOE)		26.1		31.1		83.5		99.5		30.7			28.8			59.9			57.4

Corporate Margin ($/BOE)	$	10.34	$	8.10	$	10.77	$	5.39
Non-GAAP Cash Flow Margin ($/BOE) ⁽¹⁾									$	19.09		$	12.19		$	16.46		$	10.96

(1)	Non-GAAP Cash Flow Margin was previously presented as Corporate Margin.

Debt to Adjusted Capitalization

Debt to Adjusted Capitalization is anon-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		June 30, 2018		December 31, 2017

Debt	$	4,197	$	4,198

Long-Term Debt, including current portion					$	4,198	$	4,197
Total Shareholders’ Equity		6,965		6,126		6,497		6,728

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

Adjusted Capitalization	$	18,908	$	18,070	$	18,441	$	18,671

Debt to Adjusted Capitalization		22%		23%	23%		22%

Net Debt to Adjusted EBITDA

Net Debt to Adjusted EBITDA is a non-GAAP measure whereby Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents and Adjusted EBITDA is defined as trailing 12-month net earnings (loss) before income taxes, DD&A, impairments, accretion of asset retirement obligation, interest, unrealized gains/losses on risk management, foreign exchange gains/losses, gains/losses on divestitures and other gains/losses.

Management believes this measure is useful to the Company and its investors as a measure of financial leverage, the Company’s ability to service its debt and other financial obligations, and as a measure considered comparable to other companies in the industry. This measure is used, along with other measures, in the calculation of certain financial performance targets for the Company’s management and employees.

($ millions, except as indicated)

June 30, 2018

December 31, 2017

Long-Term Debt, including current portion

$
4,198

$
4,197

Less:

Cash and cash equivalents

336

719

Net Debt

3,862

3,478

Net Earnings (Loss)

65

827

Add back (deduct):

Depreciation, depletion and amortization

1,028

833

Impairments

-

-

Accretion of asset retirement obligation

32

37

Interest

369

363

Unrealized (gains) losses on risk management

288

(442
)
Foreign exchange (gain) loss, net

(79
)

(279
)
(Gain) loss on divestitures, net

(409
)

(404
)
Other (gains) losses, net

(10
)

(42
)
Income tax expense (recovery)

543
��

603

Adjusted EBITDA

$
1,827

$
1,496

Net Debt to Adjusted EBITDA (times)

2.1

2.3

Item 3: Quantitative and ~~Qualitative~~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~~2017 Annual Report on Form10-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 andover-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 Form10-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) impactingpre-tax net earnings as follows:


	September 30, 2017				June 30, 2018
(US$ millions)	10% Price Increase		10% Price Decrease		10% Price Increase			10% Price Decrease

Crude oil price	$	(164)	$	162	$	(335	)	$	318

NGL price		(2)		2		(12	)		12

Natural gas price		(14)		7		(59	)		52

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.

The table below summarizes selected foreign exchange impacts on Encana’s financial results when compared to the same periods in 2017.

	Three Months Ended June 30,				Six Months Ended June 30,
	$ millions		$/BOE		$ millions		$/BOE
Increase (Decrease) in:
Capital Investment	$	4			$	8
Transportation and Processing Expense ⁽¹⁾		6	$	0.18		12	$	0.19
Operating Expense ⁽¹⁾		1		0.04		2		0.04
Administrative Expense		1		0.03		3		0.05
Depreciation, Depletion and Amortization ⁽¹⁾		2		0.07		5		0.09

(1)	Reflects upstream operations.

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

U.S. dollar denominated financing debt issued from Canada

●

~~U.S. dollar denominated 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~~

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~~June 30, ~~2017,~~2018, Encana ~~had $135~~has entered into $358 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$~~0.7503~~0.7606 to C$1, ~~maturing~~which mature monthly through the remainder of ~~2017~~2018 and ~~$350~~$250 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$~~0.7359~~0.7581 to C$1, ~~maturing~~which mature monthly ~~through 2018.~~throughout 2019.

As at ~~September~~June 30, ~~2017,~~2018, Encana had $4.2 billion in U.S. dollar long-term debt and ~~$332~~$278 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 rates could have resulted in unrealized gains (losses) impactingpre-tax net earnings as follows:


	September 30, 2017				June 30, 2018
(US$ millions)	10% Rate Increase		10% Rate Decrease		10% Rate Increase			10% Rate Decrease

Foreign currency exchange	$	(227)	$	277	$	(102	)	$	124

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~~June 30, ~~2017,~~2018, 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 Rules13a-15(e) and15d-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~~June 30, ~~2017.~~2018.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in Encana’s internal control over financial reporting during the ~~third~~second quarter of ~~2017~~2018 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

~~PART II~~

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~~2017 Annual Report on Form10-K and Note 21 of Encana’s Condensed Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form10-Q.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors in the ~~2016~~2017 Annual Report on Form10-K.

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

~~None.~~

Issuer Purchase of Equity Securities

On February 26, 2018, Encana announced it had received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019.

During the three months ended June 30, 2018, the Company purchased 6.8 million common shares for total consideration of approximately $89 million at a weighted average price of $13.09. The following table presents the common shares purchased during the three months ended June 30, 2018.

Period

Total Number of
Shares Purchased

Average
Price Paid
per Share ⁽¹⁾

Total Number of Shares
Purchased as Part of Publicly
Announced Plans or Programs

Maximum Number of Shares
That May Yet be Purchased
Under the Plans or Programs

April 1 to April 30, 2018

-

$
-

-

25,000,000

May 1 to May 31, 2018

5,975,000

13.17

5,975,000

19,025,000

June 1 to June 30, 2018

835,000

12.45

835,000

18,190,000

Total

6,810,000

$
13.09

6,810,000

18,190,000

⁽¹⁾ Includes commissions.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. ~~Exhibits~~Exhibits


Exhibit No		Description
~~31.1~~ 10.1		Fourth Amendment to the Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated as of May 17, 2018.
10.2		Alenco Inc. Deferred Compensation Plan amended and restated effective April 1, 2018, dated as of May 15, 2018.
31.1		Certification of Chief Executive Officer pursuant to Rule13a-14(a) or15d-14(a) of the Securities Exchange Act of 1934.
31.2		Certification of Chief Financial Officer pursuant to Rule13a-14(a) or15d-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~~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~~thereunto duly authorized.

					ENCANA CORPORATION
~~ENCANA CORPORATION~~

By:		/s/ Sherri A. Brillon

	Name:	~~Name:~~	Sherri A. Brillon
		Title:		Executive Vice-President & Chief Financial Officer

Dated: ~~November 9, 2017~~

August 2, 2018

5962

Canada		98-0355077
~~Canada~~		~~98-0355077~~
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


Large accelerated filer	[X]		Accelerated filer	[ ]

Non-accelerated filer	[ ]	(Do not check if a smaller reporting company)	Smaller reporting company	[ ]

			Emerging growth company	[ ]


		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)

		As at			As at
		June 30,			December 31,
(US$ millions)		2018			2017

Assets
Current Assets
Cash and cash equivalents		$	336		$	719
Accounts receivable and accrued revenues			813			774
Risk management	(Notes 18, 19)		174			205
Income tax receivable			535			573
			1,858			2,271
Property, Plant and Equipment, at cost:	(Note 9)
Oil and natural gas properties, based on full cost accounting
Proved properties			40,940			40,228
Unproved properties			4,108			4,480
Other			2,199			2,302
Property, plant and equipment			47,247			47,010
Less: Accumulated depreciation, depletion and amortization			(37,929	)		(38,056	)
Property, plant and equipment, net	(Note 3)		9,318			8,954
Other Assets			176			144
Risk Management	(Notes 18, 19)		185			246
Deferred Income Taxes			1,015			1,043
Goodwill	(Note 3)		2,576			2,609
	(Note 3)	$	15,128		$	15,267

Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		$	1,632		$	1,415
Income tax payable			4			7
Risk management	(Notes 18, 19)		401			236
Current portion of long-term debt	(Note 10)		500			-
			2,537			1,658
Long-Term Debt	(Note 10)		3,698			4,197
Other Liabilities and Provisions	(Note 11)		1,901			2,167
Risk Management	(Notes 18, 19)		43			13
Asset Retirement Obligation	(Note 12)		420			470
Deferred Income Taxes			32			34
			8,631			8,539
Commitments and Contingencies	(Note 21)
Shareholders’ Equity
Share capital - authorized unlimited common shares
2018 issued and outstanding: 956.3 million shares (2017: 973.1 million shares)	(Note 13)		4,674			4,757
Paid in surplus			1,358			1,358
Accumulated deficit			(575	)		(429	)
Accumulated other comprehensive income	(Note 14)		1,040			1,042
Total Shareholders’ Equity			6,497			6,728
		$	15,128		$	15,267


(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


		Number of registrant’s common shares outstanding as of ~~November 3, 2017~~July 27, 2018		~~973,114,451~~	956,344,576

	PART I
~~PART I~~

Item 1. ~~Financial Statements~~	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	37
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		56	58
Item 4.	Controls and Procedures		57	59

	PART II

Item 1. ~~Legal Proceedings~~	Legal Proceedings	58	60
Item 1A. ~~Risk Factors~~	Risk Factors	58	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		58	60
Item 3.	Defaults Upon Senior Securities		58	60
Item 4.	Mine Safety Disclosures		58	60
Item 5. ~~Other Information~~	Other Information	58	60
Item 6. ~~Exhibits~~	Exhibits	58	61
Signatures		59	62

		Three Months Ended						Six Months Ended
		June 30,						June 30,
(US$ millions, except per share amounts)		2018			2017 ⁽¹⁾			2018			2017 ⁽¹⁾

Revenues	(Notes 3, 4)
Product and service revenues		$	1,277		$	937		$	2,537		$	1,871
Gains (losses) on risk management, net	(Note 19)		(312	)		129			(276	)		467
Sublease revenues			18			17			35			34
Total Revenues			983			1,083			2,296			2,372
Operating Expenses	(Note 3)
Production, mineral and other taxes			35			24			64			53
Transportation and processing	(Note 19)		272			206			521			418
Operating	(Notes 16, 17)		137			113			248			245
Purchased product			248			192			521			363
Depreciation, depletion and amortization			300			193			575			380
Accretion of asset retirement obligation	(Note 12)		8			10			16			21
Administrative	(Notes 16, 17)		99			24			130			82
Total Operating Expenses			1,099			762			2,075			1,562
Operating Income (Loss)			(116	)		321			221			810
Other (Income) Expenses
Interest	(Note 5)		81			79			173			167
Foreign exchange (gain) loss, net	(Notes 6, 19)		25			(58	)		116			(84	)
(Gain) loss on divestitures, net			(1	)		-			(4	)		1
Other (gains) losses, net	(Note 17)		-			(27	)		(3	)		(35	)
Total Other (Income) Expenses			105			(6	)		282			49
Net Earnings (Loss) Before Income Tax			(221	)		327			(61	)		761
Income tax expense (recovery)	(Note 7)		(70	)		(4	)		(61	)		(1	)
Net Earnings (Loss)		$	(151	)	$	331		$	-		$	762
Net Earnings (Loss) per Common Share
Basic & Diluted	(Note 13)	$	(0.16	)	$	0.34		$	-		$	0.78
Dividends Declared per Common Share	(Note 13)	$	0.015		$	0.015		$	0.03		$	0.03
Weighted Average Common Shares Outstanding (millions)
Basic & Diluted	(Note 13)		960.0			973.0			965.7			973.0

Six Months Ended June 30, 2018 (US$ millions)		Share Capital			Paid in Surplus		Accumulated Deficit			Accumulated Other Comprehensive Income			Total Shareholders’ Equity

Balance, December 31, 2017		$	4,757		$	1,358	$	(429	)	$	1,042		$	6,728
Net Earnings (Loss)			-			-		-			-			-
Dividends on Common Shares	(Note 13)		-			-		(29	)		-			(29	)
Common Shares Purchased under Normal Course Issuer Bid	(Note 13)		(83	)		-		(117	)		-			(200	)
Common Shares Issued Under Dividend Reinvestment Plan	(Note 13)		-			-		-			-			-
Other Comprehensive Income (Loss)	(Note 14)		-			-		-			(2	)		(2	)
Balance, June 30, 2018		$	4,674		$	1,358	$	(575	)	$	1,040		$	6,497


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

Six Months Ended June 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)			-		-		762			-			762
Dividends on Common Shares	(Note 13)		-		-		(29	)		-			(29	)
Common Shares Issued Under Dividend Reinvestment Plan	(Note 13)		-		-		-			-			-
Other Comprehensive Income (Loss)	(Note 14)		-		-		-			(76	)		(76	)
Balance, June 30, 2017		$	4,756	$	1,358	$	(465	)	$	1,134		$	6,783

	Corporate & Other					Consolidated
	2018			2017 ⁽¹⁾		2018			2017 ⁽¹⁾

Revenues
Product and service revenues	$	-		$	-	$	1,277		$	937
Gains (losses) on risk management, net		(326	)		110		(312	)		129
Sublease revenues		18			17		18			17
Total Revenues		(308	)		127		983			1,083

Operating Expenses
Production, mineral and other taxes		-			-		35			24
Transportation and processing		-			-		272			206
Operating		5			4		137			113
Purchased product		-			-		248			192
Depreciation, depletion and amortization		12			17		300			193
Accretion of asset retirement obligation		8			10		8			10
Administrative		99			24		99			24
Total Operating Expenses		124			55		1,099			762
Operating Income (Loss)	$	(432	)	$	72		(116	)		321

Other (Income) Expenses
Interest							81			79
Foreign exchange (gain) loss, net							25			(58	)
(Gain) loss on divestitures, net							(1	)		-
Other (gains) losses, net							-			(27	)
Total Other (Income) Expenses							105			(6	)
Net Earnings (Loss) Before Income Tax							(221	)		327
Income tax expense (recovery)							(70	)		(4	)
Net Earnings (Loss)						$	(151	)	$	331

																				Market Optimization
	Market Optimization													Marketing Sales						Upstream Eliminations						Total
	Marketing Sales				Upstream Eliminations					Total
For the three months ended September 30	2017		2016		2017		2016			2017		2016
For the three months ended June 30,														2018			2017			2018			2017			2018			2017

Revenues	$	918	$	963	$	(694)	$	(749)		$	224	$	214	$	1,359		$	951		$	(1,070	)	$	(747	)	$	289		$	204

Operating Expenses
Transportation and processing		72		65		(42)		(43)			30		22		109			61			(75	)		(39	)		34			22
Operating		11		11		-		-			11		11		13			3			-			-			13			3
Purchased product		854		904		(652)		(707)			202		197		1,243			900			(995	)		(708	)		248			192
Depreciation, depletion and amortization		1		-		-		-			1		-		1			-			-			-			1			-
Operating Income (Loss)	$	(20)	$	(17)	$	-	$	1		$	(20)	$	(16)	$	(7	)	$	(13	)	$	-		$	-		$	(7	)	$	(13	)

	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


	As at September 30, 2017							As at December 31, 2016							As at June 30, 2018							As at December 31, 2017
			Accumulated							Accumulated							Accumulated							Accumulated
	Cost		DD&A			Net		Cost		DD&A			Net		Cost		DD&A			Net		Cost		DD&A			Net

Canadian Operations
Proved properties	$	14,466	$	(14,053	)	$	413	$	13,159	$	(12,896	)	$	263	$	14,246	$	(13,540	)	$	706	$	14,555	$	(14,047	)	$	508
Unproved properties		322		-			322		285		-			285		243		-			243		311		-			311
Other		45		-			45		54		-			54		32		-			32		43		-			43
		14,833		(14,053	)		780		13,498		(12,896	)		602		14,521		(13,540	)		981		14,909		(14,047	)		862

USA Operations
Proved properties		25,059		(23,079	)		1,980		26,393		(25,300	)		1,093		26,635		(23,627	)		3,008		25,610		(23,240	)		2,370
Unproved properties		4,362		-			4,362		4,913		-			4,913		3,865		-			3,865		4,169		-			4,169
Other		21		-			21		44		-			44		16		-			16		16		-			16
		29,442		(23,079	)		6,363		31,350		(25,300	)		6,050		30,516		(23,627	)		6,889		29,795		(23,240	)		6,555

Market Optimization		7		(5	)		2		6		(4	)		2		7		(6	)		1		7		(5	)		2
Corporate & Other		2,302		(753	)		1,549		2,148		(663	)		1,485		2,203		(756	)		1,447		2,299		(764	)		1,535
	$	46,584	$	(37,890	)	$	8,694	$	47,002	$	(38,863	)	$	8,139	$	47,247	$	(37,929	)	$	9,318	$	47,010	$	(38,056	)	$	8,954


	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


	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


	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	)


	As at September 30, 2017				As at December 31, 2016				As at June 30, 2018						As at December 31, 2017
	Number (millions)		Amount		Number (millions)		Amount		Number (millions)			Amount			Number (millions)		Amount

Common Shares Outstanding, Beginning of Year		973.0	$	4,756		849.8	$	3,621		973.1		$	4,757			973.0	$	4,756
Common Shares Issued		-		-		123.1		1,134
Common Shares Purchased										(16.8	)		(83	)		-		-
Common Shares Issued Under Dividend Reinvestment Plan		0.1		1		0.1		1		-			-			0.1		1
Common Shares Outstanding, End of Period		973.1	$	4,757		973.0	$	4,756		956.3		$	4,674			973.1	$	4,757


	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


	As at September 30, 2017				As at September 30, 2016				As at June 30, 2018		As at June 30, 2017
	US$ Share Units		C$ Share Units		US$ Share Units		C$ Share Units		US$ Share Units	C$ Share Units	US$ Share Units	C$ Share Units

Risk Free Interest Rate		1.53%		1.53%		0.49%		0.49%	1.84%	1.84%	1.09%	1.09%
Dividend Yield		0.51%		0.53%		0.57%		0.58%	0.46%	0.45%	0.68%	0.70%
Expected Volatility Rate⁽¹⁾		59.35%		55.21%		56.11%		52.27%	57.6%	54.1%	59.17%	54.94%
Expected Term		1.6 yrs		1.7 yrs		1.6 yrs		1.8 yrs	1.8 yrs	2.0 yrs	1.9 yrs	1.9 yrs
Market Share Price		US$11.78		C$14.69		US$10.47		C$13.71	US$13.05	C$17.17	US$8.80	C$11.41


	As at September 30, 2017		As at December 31, 2016		As at June 30, 2018		As at December 31, 2017

Liability for Cash-Settled Share-Based Payment Transactions:
Unvested	$	204	$	171	$	255	$	274
Vested		43		37		64		53
	$	247	$	208	$	319	$	327


~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2018 (thousands of units)

TSARs			~~850~~ 872
SARs			~~349~~ 359
PSUs			~~1,979~~ 2,515
DSUs			~~148~~ 32
RSUs			~~4,893~~ 5,275


	Pension Benefits				OPEB				Total				Pension Benefits					OPEB				Total
	2017		2016		2017		2016		2017		2016		2018		2017			2018		2017		2018		2017

Net Defined Periodic Benefit Cost	$	-	$	(1)	$	1	$	10	$	1	$	9	$	-	$	(1	)	$	3	$	5	$	3	$	4
Defined Contribution Plan Expense		17		21		-		-		17		21		12		12			-		-		12		12
Total Benefit Plans Expense	$	17	$	20	$	1	$	10	$	18	$	30	$	12	$	11		$	3	$	5	$	15	$	16


	Defined Benefits				OPEB				Total				Defined Benefits						OPEB						Total
	2017		2016		2017		2016		2017		2016		2018			2017			2018			2017			2018			2017

Service Cost	$	1	$	1	$	6	$	8	$	7	$	9	$	-		$	-		$	3		$	4		$	3		$	4
Interest Cost		6		6		2		3		8		9		4			4			1			2			5			6
Expected Return on Plan Assets		(7)		(8)		-		-		(7)		(8)		(4	)		(5	)		-			-			(4	)		(5	)
Amounts Reclassified from Accumulated Other Comprehensive Income:
Amortization of net actuarial (gains) and losses		-		-		(1)		(1)		(1)		(1)		-			-			(1	)		(1	)		(1	)		(1	)
Curtailment		-		-		(1)		-		(1)		-
Curtailment		-		-		(5)		-		(5)		-
Total Net Defined Periodic Benefit Cost	$	-	$	(1)	$	1	$	10	$	1	$	9
Total Net Defined Periodic Benefit Cost ⁽¹⁾													$	-		$	(1	)	$	3		$	5		$	3		$	4


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
As at June 30, 2018													Level 1 Quoted Prices in Active Markets		Level 2 Other Observable Inputs		Level 3 Significant Unobservable Inputs		Total Fair Value		Netting ⁽¹⁾			Carrying Amount

Risk Management Assets
Commodity Derivatives:
Current assets	$	-	$	133	$	-	$	133	$	(57)	$	76	$	7	$	293	$	-	$	300	$	(129	)	$	171
Long-term assets		-		90		-		90		(14)		76		-		198		-		198		(14	)		184
Foreign Currency Derivatives:
Current assets		-		31		-		31		-		31		-		3		-		3		-			3
Long-term assets		-		8		-		8		-		8		-		1		-		1		-			1

Risk Management Liabilities
Commodity Derivatives:
Current liabilities	$	10	$	59	$	5	$	74	$	(57)	$	17	$	-	$	431	$	98	$	529	$	(129	)	$	400
Long-term liabilities		1		22		2		25		(14)		11		-		38		19		57		(14	)		43

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		-		1		-		1		-			1

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

Long-term in other liabilities and provisions		-		14		-		14		-		14		-		12		-		12		-			12


	Notional Volumes		Term	Average Price	Fair Value			Notional Volumes	Term	Average Price		Fair Value

Crude Oil and NGL Contracts				US$/bbl						US$/bbl

Fixed Price Contracts
WTI Fixed Price		33.0 Mbbls/d	2017	52.27	$	1		102.3 Mbbls/d	2018		55.52	$	(280	)
WTI Fixed Price		59.2 Mbbls/d	2018	52.95		24		35.0 Mbbls/d	2019		60.31		(62	)
Propane Fixed Price								9.0 Mbbls/d	2018		39.05		(1	)
Butane Fixed Price		2.5 Mbbls/d	2017	36.12		(2	)	7.0 Mbbls/d	2018		43.49		(2	)

WTI Fixed Price Swaptions ⁽¹⁾								24.0 Mbbls/d	Q1 - Q2 2019		63.13		(29	)

WTI Three-Way Options
Sold call / bought put / sold put		25.0 Mbbls/d	2017	61.40 / 49.95 / 39.40		2		16.0 Mbbls/d	2018	54.49 / 47.17 / 36.88			(46	)

WTI Three-Way Options
Sold call / bought put / sold put		10.0 Mbbls/d	2018	54.19 / 45.00 / 35.00		(7	)	42.0 Mbbls/d	2019	68.38 / 59.11 / 48.21			(47	)

WTI Costless Collars
Sold call / bought put		30.0 Mbbls/d	2017	56.05 / 46.22		(1	)	10.0 Mbbls/d	2018	57.08 / 45.00			(24	)

WTI Costless Collars
Sold call / bought put		10.0 Mbbls/d	2018	57.08 / 45.00		(1	)
Basis Contracts ⁽²⁾									2018				60
									2019 - 2020				40
Basis Contracts⁽¹⁾			2017 - 2020			(20	)

Crude Oil and NGLs Fair Value Position						(4	)						(391	)

Natural Gas Contracts				US$/Mcf						US$/Mcf

Fixed Price Contracts
NYMEX Fixed Price		405 MMcf/d	2017	3.13		3		1,084 MMcf/d	2018		3.02		14
NYMEX Fixed Price		650 MMcf/d	2018	3.07		6		699 MMcf/d	2019		2.72		(20	)

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 Fixed Price Swaptions ⁽³⁾								300 MMcf/d	Q1 - Q2 2019		2.99		(8	)

NYMEX Call Options
Sold call price		230 MMcf/d	2018	3.75		(8	)	230 MMcf/d	2018		3.75		(1	)
Sold call price		230 MMcf/d	2019	3.75		(9	)	230 MMcf/d	2019		3.75		(4	)
Bought call price								230 MMcf/d	2019		3.75		-
Sold call price								230 MMcf/d	2020		3.25		-

Basis Contracts⁽²⁾			2017 2018 2019 2020 - 2023			13 60 39 25
Basis Contracts ⁽⁴⁾									2018				77
									2019				127
									2020				94
									2021 - 2023				28

Natural Gas Fair Value Position						128							307

Net Premiums Received on Unexpired Options													(4	)

Other Derivative Contracts

Fair Value Position						(21	)						(17	)

Foreign Currency Contracts

Fair Value Position⁽³⁾			2017 - 2018			39
Total Fair Value Position					$	142
Fair Value Position ⁽⁵⁾									2018 - 2019				3
Total Fair Value Position and Net Premiums Received												$	(102	)


	Three Months Ended				Nine Months Ended				Three Months Ended						Six Months Ended
	September 30,				September 30,				June 30,						June 30,
	2017		2016		2017		2016		2018			2017			2018			2017

Realized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues⁽¹⁾	$	41	$	54	$	36	$	358	$	14		$	19		$	(18	)	$	(5	)
Transportation and processing		-		-		(4)		(4)		-			-			-			(4	)
Foreign Currency Derivatives:
Foreign exchange		9		-		8		-		3			(2	)		10			(1	)
	$	50	$	54	$	40	$	354	$	17		$	17		$	(8	)	$	(10	)

Unrealized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues⁽²⁾	$	(76)	$	42	$	396	$	(469)	$	(326	)	$	110		$	(258	)	$	472
Transportation and processing		-		(1)		-		4
Foreign Currency Derivatives:
Foreign exchange		14		-		40		-		(8	)		24			(26	)		26
	$	(62)	$	41	$	436	$	(465)	$	(334	)	$	134		$	(284	)	$	498

Total Realized and Unrealized Gains (Losses) on Risk Management, net
Commodity and Other Derivatives:
Revenues^{(1) (2)}	$	(35)	$	96	$	432	$	(111)	$	(312	)	$	129		$	(276	)	$	467
Transportation and processing		-		(1)		(4)		-		-			-			-			(4	)
Foreign Currency Derivatives:
Foreign exchange		23		-		48		-		(5	)		22			(16	)		25
	$	(12)	$	95	$	476	$	(111)	$	(317	)	$	151		$	(292	)	$	488


	Expected Future Payments														Expected Future Payments
(undiscounted)		2017		2018		2019		2020		2021		Thereafter		Total	2018		2019		2020		2021		2022		Thereafter		Total

Transportation and Processing	$	120	$	525	$	599	$	573	$	452	$	2,761	$	5,030	$	294	$	692	$	669	$	582	$	555	$	2,516	$	5,308
Drilling and Field Services		101		79		34		18		8		-		240		123		50		24		9		-		-		206
Operating Leases		4		18		16		16		15		61		130		9		17		16		16		16		50		124
Total	$	225	$	622	$	649	$	607	$	475	$	2,822	$	5,400	$	426	$	759	$	709	$	607	$	571	$	2,566	$	5,638


	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


	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

Period	Total Number of Shares Purchased		Average Price Paid per Share ⁽¹⁾		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares That May Yet be Purchased Under the Plans or Programs
April 1 to April 30, 2018		-	$	-		-		25,000,000
May 1 to May 31, 2018		5,975,000		13.17		5,975,000		19,025,000
June 1 to June 30, 2018		835,000		12.45		835,000		18,190,000
Total		6,810,000	$	13.09		6,810,000		18,190,000