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News Releases

Encana delivers strong fourth quarter and full-year 2016 results; company on track to grow corporate margin and crude and condensate production in 2017

CALGARY, AB --(Marketwired - February 16, 2017) - (TSX: ECA) (NYSE: ECA)

Encana delivered strong performance across its business in the fourth quarter, positioning itself to create value and return to growth in 2017. Throughout 2016, Encana grew quarter-over-quarter non-GAAP cash flow, significantly lowered costs, strengthened its balance sheet and continued to deliver better wells at lower cost in each of its core assets. The company reached its planned 2017 activity level in the fourth quarter to launch itself into 2017, when it expects to deliver strong growth in crude and condensate production and increase its non-GAAP corporate margin. The company is firmly on track with its five-year plan. Fourth quarter and full-year highlights from 2016 include:

--  fourth quarter production from core assets of 237,100 barrels of oil

    equivalent per day (BOE/d), representing 74 percent of total production

--  fourth quarter total liquids production of 108,900 barrels per day

    (bbls/d) including oil and plant condensate production of 86,300 bbls/d,

    representing almost 80 percent of total liquids production

--  fourth quarter cash from operating activities of $199 million and non-

    GAAP cash flow of $302 million

--  lowered full-year average drilling and completion costs by about 30

    percent compared to 2015

--  drove further efficiency across the business, delivering more than $600

    million of savings compared to 2015

--  reduced long-term debt by $1.1 billion from 2015 and net debt by more

    than 50 percent since year-end 2014

--  generated full-year cash from operating activities of $625 million and

    non-GAAP cash flow of $838 million

--  replaced 326 percent of full-year 2016 production on a proved plus

    probable reserves basis after royalties (Canadian protocols) and 175

    percent of full-year 2016 production on an SEC proved reserves basis

    (U.S. protocols), excluding dispositions

"We delivered on our 2016 strategic objectives and our performance through the fourth quarter created a powerful launch pad for our five-year growth plan," said Doug SuttlesEncana President & CEO. "We drove innovation and efficiency into every part of our business to increase margins and returns and we have one of the largest premium return drilling inventories in our industry. Our high quality multi-basin portfolio and leading operational performance positions us to generate strong returns at today's prices."

"We carried considerable momentum into 2017," added Suttles. "Through innovation and our relentless focus on efficiency and supply chain management, we expect to hold total year-over-year drilling and completion costs flat despite cost inflation for some services. We expect to significantly increase crude and condensate production throughout the year and deliver strong corporate margin growth."

Better wells at lower cost Encana's focus on operational excellence, stacked pay zones and developing its premium return well inventory has positioned the company as an operational leader in each of its core assets. In 2016, Encana had 10,000 premium return well locations and the company anticipates growing that inventory through 2017. Already in 2017, Encana has added 50 premium return well locations to its Eagle Ford inventory. Harnessing the competitive advantages of its high quality multi-basin portfolio, Encana rapidly applies technical advancements and efficiencies across its core assets to deliver better wells at lower cost. Highlights in 2016 include:

--  In the Permian, Encana's latest completion designs are delivering strong

    well performance. Two new Midland County wells delivered average 30-day

    initial production rates of 1,200 BOE/d, including 900 bbls/d of oil.

    Two new Howard County wells averaged 30-day initial production rates of

    about 1,200 BOE/d, including approximately 1,050 bbls/d of oil. During

    the fourth quarter, Encana maintained its leading drilling and

    completions costs to deliver average normalized drilling and completion

    costs of $5 million per well. Average full-year 2016 normalized drilling

    and completion costs were 30 percent lower than in 2015. The company

    grew total 2016 production by 20 percent compared to 2015. In 2017,

    Encana aims to grow value and improve well productivity through

    optimized completion designs, which have the potential to further expand

    its premium return well inventory. The company expects to grow

    production by approximately 50 percent from the fourth quarter of 2016

    to the fourth quarter of 2017.

--  In the Eagle Ford, the company used optimized completion designs on

    three new Eagle Ford wells which out-performed expectations, delivering

    average 90-day initial production rates of 1,450 BOE/d. Encana's newest

    Austin Chalk well delivered a 30-day initial production rate of 1,000

    BOE/d. This latest well is approximately 25 miles from the first two

    wells, indicating Austin Chalk potential across a sizable portion of

    Encana's acreage. Encana has added an additional 50 premium return wells

    to its Eagle Ford inventory. Average 2016 normalized drilling and

    completion costs were 23 percent lower than in 2015. In 2017, Encana

    plans to drill between 10 and 15 Austin Chalk wells. The company is

    focused on enhancing well performance through new completion designs

    across the play and believes there is potential to further expand its

    premium return well inventory.

--  In the Montney, the company delivered a 50 percent well productivity

    improvement from a new well by applying a completion design similar to

    one successfully pioneered in the Eagle Ford 12 weeks earlier. Encana

    continues to ramp up activity in the Cutbank Ridge area of the play in

    preparation for two midstream processing plants becoming operational in

    the fourth quarter of 2017. Construction for both plants remains on

    schedule and under budget. The company's average normalized drilling and

    completion costs in the fourth quarter were $4.4 million per well while

    average full-year 2016 normalized drilling and completion costs were

    about 25 percent lower than in 2015. Encana grew total 2016 liquids

    production by six percent from 2015 (excluding Gordondale). In 2017,

    Encana will focus on liquids-rich locations where the program is

    expected to deliver an average 85 barrels of liquids per million cubic

    feet of gas (bbls/MMcf). The company plans to more than double liquids

    production from the fourth quarter of 2016 to the fourth quarter of 2017

    with condensate expected to make up 85 percent of the production growth.

--  In the Duvernay, the company successfully ramped up production through

    the 10-29 processing facility which was brought online in mid-2016. Two

    new wells in the volatile oil window are exceeding expectations and

    delivered 60-day initial production rates of about 1,500 BOE/d with

    nearly 1,000 bbls/d of condensate. Encana grew total 2016 production by

    86 percent compared to 2015. Average 2016 normalized drilling and

    completion costs were 45 percent lower than in 2015. Throughout 2017,

    Encana will assess the potential for premium return drilling inventory

    expansion in the volatile oil window and delineate the stacked pay

    potential of the Montney zone within the play.

Lower costs, lower debt and significant liquidity Encana delivered over $600 million in cost efficiencies compared to 2015. The company reduced its long-term debt by $1.1 billion through 2016. At year-end, long-term debt totalled approximately $4.2 billion and net debt was about $3.4 billionEncana concluded 2016 with approximately $5.3 billion of liquidity made up of $4.5 billion in available credit facilities and cash and cash equivalents of $834 million on its balance sheet, compared to cash and cash equivalents of $271 million at year-end 2015.

2016 fourth quarter and year-end results During the fourth quarter of 2016, Encana delivered cash from operating activities of $199 million and non-GAAP cash flow of $302 million or $0.31 per share. Full-year 2016 cash from operating activities was $625 million and non-GAAP cash flow was $838 million or $0.95 per share.

Encana reported a fourth quarter net loss of $281 million, or $0.29 per share, and a full-year net loss of $944 million, or $1.07 per share, including $938 million of after-tax, non-cash ceiling test impairments, a net loss on risk management and a deferred tax valuation allowance, partially offset by gains on divestitures and foreign exchange. Fourth quarter non-GAAP operating earnings were $85 million, or $0.09 per share. Full-year non-GAAP operating earnings were $76 million, or $0.09 per share.

Encana's core assets contributed 74 percent of total fourth quarter production of 321,500 BOE/d and 72 percent of the full-year average of 352,700 BOE/d. Full-year liquids production averaged 122,100 bbls/d representing approximately 35 percent of the company's production mix. Encana expects to grow liquids volumes to over 40 percent of total production in the fourth quarter of 2017. Natural gas production in 2016 averaged 1,383 million cubic feet per day (MMcf/d).

2017 capital and production guidance: Delivering efficient growth Encana's 2017 capital program is expected to be between $1.6 billion and $1.8 billion. Total production is expected to be between 320,000 BOE/d and 330,000 BOE/d. Encana plans to grow crude and condensate production by more than 35 percent through 2017 and production from its core assets by more than 20 percent from the fourth quarter of 2016 to the fourth quarter of 2017. The company estimates total liquids volumes will average between 125,000 bbls/d and 130,000 bbls/d with natural gas production between 1,150 MMcf/d to 1,200 MMcf/d.

With its premium return well inventory, expected growth in crude and condensate production and cost efficiencies, Encanaexpects to deliver a corporate margin of greater than $10 per barrel of oil equivalent (BOE) in 2017. Encana plans to fund its 2017 capital program with cash flows and cash on hand. Encana's 2017 guidance can be downloaded from the company's website at http://www.encana.com/investors/financial/corporate-guidance.html.

Encana updates its risk management program The combination of Encana's multi-basin portfolio, 100 percent short-cycle capital program and robust hedge strategy uniquely positions the company to effectively manage risk.

Encana enters 2017 with a strong risk management position to significantly mitigate commodity price uncertainty. As at January 31, 2017Encana had hedged approximately 79,000 bbls/d of expected 2017 crude and condensate production for the balance of the year using a variety of structures at an average price of $53.56 per barrel. In addition, the company has hedged about 860 MMcf/d of expected 2017 natural gas production for the balance of the year using a variety of structures at an average price of $3.13 per thousand cubic feet (Mcf).

Dividend declared

On February 15, 2017, the Board declared a dividend of $0.015 per share payable on March 31, 2017 to common shareholders of record as of March 15, 2017.


                      Non-GAAP Cash Flow Reconciliation


(for the period ended December


($ millions, except per share        Q4         Q4

 amounts)                           2016       2015       2016       2015


Cash from (used in) operating           199        448        625      1,681


Deduct (add back):

  Net change in other assets and

   liabilities                         (11)          7       (26)       (11)

  Net change in non-cash working

   capital                             (92)         58      (187)        262


Non-GAAP cash flow1                     302        383        838      1,430


                 Non-GAAP Operating Earnings Reconciliation


Net earnings (loss)                   (281)      (612)      (944)    (5,165)

Before-tax (addition) deduction:

  Unrealized gain (loss) on risk

   management                         (149)       (90)      (614)      (331)

  Impairments                             -      (805)    (1,396)    (6,473)

  Non-operating foreign exchange

   gain (loss)                        (104)      (106)        135      (776)

  Restructuring charges                 (1)        (5)       (34)       (64)

  Gain (loss) on divestitures           (3)          -        390         14

  Gain on debt retirement                 -          -         89          -


                                      (257)    (1,006)    (1,430)    (7,630)

Income tax                            (109)        283        410      2,526


After-tax (addition) deduction        (366)      (723)    (1,020)    (5,104)


Non-GAAP operating earnings              85        111         76       (61)

 (loss) (1)

Non-GAAP operating earnings

 (loss) per share                      0.09       0.13       0.09     (0.07)


(1) Non-GAAP cash flow and non-GAAP operating earnings are non-GAAP measures as defined in Note 1.


                             Production Summary


(for the period ended December 31)         Q4   Q4

(average)                                 2016  2015  % ∆  2016  2015   % ∆


Natural gas (MMcf/d)                     1,276 1,571  (19) 1,383 1,635  (15)


Oil and NGLs (Mbbls/d)                   108.9 145.0  (25) 122.1 133.4   (8)


Total production (MBOE/d)                321.5 406.8  (21) 352.7 405.9  (13)



                       Natural Gas and Liquids Prices


                                          Q4 2016  Q4 2015   2016     2015


Natural gas


NYMEX ($/MMBtu)                              2.98     2.27     2.46     2.66

Encana realized natural gas price(1)

 ($/Mcf)                                     2.35     3.43     2.10     3.89


Oil and NGLs($/bbl)


WTI                                         49.29    42.18    43.32    48.80

Encana realized liquids price(1)            42.96    39.11    38.85    39.93


(1) Prices include the impact of realized gain (loss) on risk management.

Year-End 2016 Reserves Estimates


   2016 Reserves Estimates - Canadian Protocols (Net, After Royalties)(1)


Using forecast prices and costs;                                      3P

 simplified table                                         2P       Proved +

                                              1P       Proved +   Probable +

(MMBOE)                                     Proved     Probable    Possible


Canadian Operations                              481       1,213       1,469


USA Operations                                   439         825         903


Total as of December 31, 2016                    920       2,038       2,372



       2016 Proved Reserves Estimates - Canadian Protocols (Net, After



Using forecast prices and costs;         Natural Gas  Oil & NGLs    Total

 simplified table.                          (Bcf)      (MMbbls)    (MMBOE)


December 31, 2015                              4,076       380.1     1,059.5

Extensions, improved recovery and

 discoveries                                     515        75.9       161.8

Revisions and economic factors                 (149)      (17.5)      (42.2)

Acquisitions                                      17        13.0        15.9

Dispositions                                   (427)      (75.0)     (146.1)

Production                                     (506)      (44.7)     (129.1)


December 31, 2016                              3,527       332.0       919.9



  2016 Proved Reserves Estimates - U.S. Protocols (Net, After Royalties)(1)


Using constant prices and costs;       Natural Gas  Oil & NGLs     Total

 simplified table.                        (Bcf)      (MMbbls)     (MMBOE)


December 31, 2015                            3,064       288.8         799.4

Revisions and improved recovery              (244)      (23.9)        (64.7)

Extensions and discoveries                     887       128.0         275.7

Purchase of reserves in place                   16        12.2          14.9

Sale of reserves in place                    (313)      (54.4)       (106.5)

Production                                   (506)      (44.7)       (129.1)


December 31, 2016                            2,902       306.0         789.7


(1) Numbers may not add due to rounding.

Encana replaced 326 percent of full-year 2016 production on an NI 51-101 (Canadian protocol) proved plus probable reserves basis after royalties and 175 percent of full-year 2016 production on an SEC (U.S. protocol) proved reserves basis, excluding dispositions. The changes were primarily due to Encana's continued execution and increased investment in its core assets.

Differences between estimates under Canadian and U.S. protocols primarily represent the use of forecast prices in the estimation of reserves under Canadian standards, while U.S. standards require the use of 12-month average historical prices which are held constant. For information on reserves reporting, see Note 2.

Estimated Risked Economic Contingent Resources


Net (after royalties) using  Estimated Risked Economic Contingent Resources

 forecast prices and costs.                      (MMBOE)


                            Contingent        1C          2C          3C

                            Resource         Low         Best        High

                            Sub-class      estimate    estimate    estimate



Canadian Operations         Pending            1,502       1,876       2,235



                            On Hold               25          38          48




USA Operations              Pending            1,513       1,721       1,920



                            On Hold              257         653         804



Total as of December 31,    Development

 2016                       Pending            3,015       3,597       4,155



                            On Hold              282         691         852


For information on reserves and economic contingent resources, see Advisory Regarding Reserves & Other Resources Information.

Conference call information Encana will host a conference call today, Thursday, February 16, 2017 starting at 7:00 a.m. MT (9:00 a.m. ET). To participate, please dial (844) 707-0663 (toll-free in North America) or (703) 326-3003 (international) approximately 10 minutes prior to the conference call. A live audio webcast of the conference call, including slides, will also be available on Encana's website, www.encana.com, under Invest in Us/Presentations & Events. The webcast will be archived for approximately 90 days.

Encana Corporation Encana Corporation ("Encana") is a leading North American energy producer that is focused on developing its strong portfolio of resource plays, held directly and indirectly through its subsidiaries, producing natural gas, oil and natural gas liquids (NGLs). By partnering with employees, community organizations and other businesses, Encanacontributes to the strength and sustainability of the communities where it operates. Encana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.

Important Information Encana reports in U.S. dollars unless otherwise noted. Production, sales and reserves estimates are reported on a net (after-royalties) basis, unless otherwise noted. The term liquids is used to represent oil, NGLs and condensate. The term liquids-rich is used to represent natural gas streams with associated liquids volumes. Unless otherwise specified or the context otherwise requires, references to Encana or to the company includes reference to subsidiaries of and partnership interests held by Encana Corporation and its subsidiaries.

NOTE 1: Non-GAAP measures

This news release contains references to non-GAAP measures as follows:

--  Non-GAAP Cash flow is a non-GAAP measure defined as cash from operating

    activities excluding net change in other assets and liabilities, net

    change in non-cash working capital and current tax on sale of assets.

    Corporate Margin is a non-GAAP measure defined as Non-GAAP Cash Flow per

    BOE of production.

--  Non-GAAP Operating earnings (loss) is a non-GAAP measure defined as net

    earnings (loss) excluding non-recurring or non-cash items that

    management believes reduces the comparability of the company's financial

    performance between periods. These items may include, but are not

    limited to, unrealized gains/losses on risk management, impairments,

    restructuring charges, non-operating foreign exchange gains/losses,

    gains/losses on divestitures and gains on debt retirement. Income taxes

    may include valuation allowances and the provision related to the pre-

    tax items listed, as well as income taxes related to divestitures and

    adjustments to normalize the effect of income taxes calculated using the

    estimated annual effective income tax rate.

--  Net Debt is a non-GAAP measure defined as long-term debt, including the

    current portion, less cash and cash equivalents. Management uses this

    measure as a substitute for total long-term debt in certain internal

    debt metrics as a measure of the company's ability to service debt

    obligations and as an indicator of the company's overall financial


NOTE 2: Information on reserves reporting - Detailed Canadian protocol disclosure will be contained in Encana's Form 51-101F1 for the year ended December 31, 2016 ("Form 51-101F1") and detailed U.S. protocol disclosure will be contained in Encana's Annual Report on Form 10-K for the year ended December 31, 2016 ("Annual Report on Form 10-K"), each of which Encana anticipates filing with applicable securities regulatory authorities on or about February 27, 2017. A description of the primary differences between the disclosure requirements under Canadian standards and under U.S. standards will be set forth under the heading "Note Regarding Reserves Data and Other Oil and Gas Information" in the Form 51-101F1.

ADVISORY REGARDING RESERVES & OTHER RESOURCES INFORMATION - All estimates in this news release are effective as of December 31, 2016, prepared by qualified reserves evaluators in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook, National Instrument 51-101 and SECregulations, as applicable, and are audited by independent qualified reserves auditors engaged by Encana. Detailed Canadian and U.S. protocol disclosure will be contained in the Form 51-101F1 and Annual Report on Form 10-K, respectively, as described in Note 2. Additional detail regarding Encana's economic contingent resources disclosure will be available in the Supplemental Disclosure Document filed concurrently with the Form 51-101F1. Information on the forecast prices and costs used in preparing the Canadian protocol estimates will be contained in the Form 51-101F1. For additional information relating to risks associated with the estimates of reserves and resources, see "Item 1A. Risk Factors" of the Annual Report on Form 10-K.

Reserves are the estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: analysis of drilling, geological, geophysical and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are those reserves which can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. A low estimate (1C) is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate, which under probabilistic methodology reflects at least a 90 percent confidence level. A best estimate (2C) is considered to be a realistic estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, which under probabilistic methodology reflects at least a 50 percent confidence level. A high estimate (3C) is considered to be an optimistic estimate. It is unlikely that the actual remaining quantities recovered will exceed the high estimate, which under probabilistic methodology reflects at least a 10 percent confidence level. There is uncertainty that it will be commercially viable to produce any portion of the resources.

All of the resources classified as contingent are considered to be discovered, and as such have been assigned a 100 percent chance of discovery, but have however been risked for the chance of development. The chance of development is defined as the likelihood of a project being commercially viable and development proceeding in a timely fashion. Determining the chance of development requires taking into consideration each contingency and quantifying the risks into an overall development risk factor at a project level.

All of the contingent resources disclosed in the above table are classified as either Development Pending or Development On Hold. Development Pending is where resolution of the final conditions for development is being actively pursued (high chance of development). Resources classified in this sub-category must be economic and have been assigned a chance of development ranging between 80 percent and 99 percent. Development On Hold is where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator. Resources classified in this sub-category must be economic and have been assigned a chance of development ranging between 50 percent and 79 percent.

Contingent resources are categorized as economic if those contingent resources have a positive net present value under currently forecasted prices and costs. In examining economic viability, the same fiscal conditions have been applied as in the estimation of Encana's reserves. Contingencies include factors such as required corporate or third party (such as joint venture partners) approvals, legal, environmental, political and regulatory matters or a lack of infrastructure or markets.

The conversion of natural gas volumes to barrels of oil equivalent (BOE) is on the basis of six thousand cubic feet to one barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be misleading, particularly if used in isolation. 30-day initial or peak production and other short-term rates are not necessarily indicative of long-term performance or of ultimate recovery.

Drilling and completions costs in the Permian, Eagle FordDuvernay and Montney have been normalized based on lateral lengths of 7,500 feet, 5,000 feet, 8,200 feet and 9,000 feet, respectively. Disclosure of estimated well locations include proved, probable, contingent and unbooked locations. These estimates are prepared internally based on Encana'sprospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Approximately 40 percent of all locations specified in our core assets are booked as either reserves or resources, as prepared by internal qualified reserves evaluators using forecast prices and costs as ofDecember 31, 2016. Unbooked locations do not have attributed reserves or resources and have been identified by management as an estimation of Encana's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Encana will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The locations on which Encana will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of capital, regulatory and partner approvals, seasonal restrictions, equipment and personnel, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained, production rate recovery, transportation constraints and other factors. While certain of the unbooked locations have been de-risked by drilling existing wells in relative close proximity to such locations, many of other unbooked locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional proved or probable reserves, resources or production. Premium return well inventory are locations with expected after tax returns greater than 35 percent at $50/bbl WTI and $3/MMBtu NYMEX.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - This news release contains certain forward-looking statements or information (collectively, "FLS") within the meaning of applicable securities legislation. FLS include: expected growth in corporate margin and crude and condensate production; anticipated value creation and growth in 2017; achieving metrics in Encana's five-year plan; anticipated reserves and resources; performance and efficiency of Encana's assets relative to its peers; anticipated production, composition of commodity mix, cash flow, returns and corporate margins; application of technical innovation across the core assets; ability to improve well productivity through optimizing completion design; ability to manage cost inflation and expected cost structures, including expected drilling and completions costs; focus of capital on and amount of premium return well inventory; advantages of Encana's multi-basin portfolio; costs and timing of processing plants being operational; planned drilling and addition to premium return well inventory; funding for and amount of 2017 capital program, including allocation thereof; expectation of meeting the targets in Encana's 2017 corporate guidance; anticipated hedging and outcomes of risk management program, including amount of hedged production; and anticipated dividends.

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

Risks and uncertainties that may affect these business outcomes include: the ability to generate sufficient cash flow to meet Encana's obligations; risks inherent to completing transactions on a timely basis or at all and adjustments that may impact the expected value to Encana; commodity price volatility; ability to secure adequate product transportation and potential pipeline curtailments; variability and discretion of Encana's board of directors to declare and pay dividends, if any; the timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk; risk and effect of a downgrade in credit rating, including below an investment-grade credit rating, and its impact on access to capital markets and other sources of liquidity; fluctuations in currency and interest rates; risks inherent in Encana's corporate guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential future lawsuits and regulatory actions made against Encana; impact to Encana as a result of disputes arising with its partners, including the suspension by its partners of certain of their obligations and the inability to dispose of assets or interests in certain arrangements; Encana's ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as "partnerships" or "joint ventures" and the funds received in respect thereof which Encana may refer to from time to time as "proceeds", "deferred purchase price" and/or "carry capital", regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties impacting Encana's business, as described in its most recent Annual Report on Form 10-K and as described from time to time in Encana's other periodic filings as filed on SEDAR and EDGAR.

Although Encana believes the expectations represented by such FLS are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. FLS are made as of the date of this news release and, except as required by law, Encana undertakes no obligation to update publicly or revise any FLS. The FLS contained in this news release are expressly qualified by these cautionary statements.

SOURCE: Encana Corporation


Further information on Encana Corporation is available on the company's website, www.encana.com, or by contacting:

Investor contact:

Brendan McCracken

Vice-President, Investor Relations

(403) 645-2978

Patti Posadowski

Sr. Advisor, Investor Relations

(403) 645-2252

Media contact:

Simon Scott

Vice-President, Communications

(403) 645-2526

Jay Averill

Director, Media Relations

(403) 645-4747

Source: Encana Corporation