Report of Foreign Issuer (6-k)

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 under the Securities Exchange Act of 1934


For: March 27, 2015		Commission File Number: 1-15226

ENCANA CORPORATION

(Translation of registrant’s name into English)

Suite 4400, 500 Centre Street SE

PO Box 2850

Calgary, Alberta, Canada T2P 2S5

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20- F Form 40-F ü

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

DOCUMENTS FILED AS PART OF THIS FORM 6-K

See the Exhibit Index to this Form 6-K.

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, thereunto duly authorized.

Date: March 27, 2015

ENCANA CORPORATION

(Registrant)

By:

/s/ Jocelyn S. Salazar


				Name:		Jocelyn S. Salazar
				Title:		Assistant Corporate Secretary

Form 6-K Exhibit Index


Exhibit No.

99.1		2014 Annual Report

Exhibit 99.1

LOGO

A transformative year

2014 was a remarkable year for Encana. The successful execution of the strategy, which is built around a disciplined focus on profitable growth, saw the company complete virtually all of its key deliverables two years ahead of schedule. The speed of this achievement demonstrates the effectiveness of the strategy and the highly driven culture built by Doug Suttles and his leadership team.

Entering the year, Encana embarked on the right course of action at the right time by restructuring and resizing its organization, resulting in an approximately 25 percent workforce reduction. The company modified core processes such as capital allocation which led to a focused investment on seven growth assets, down from almost 30 funded areas the prior year. Strong efficiency improvements across the company highlighted Encana’s relentless drive for operational excellence.

The year was also marked by the transformation of Encana’s portfolio with the divestiture of non-core assets, including the initial public offering and secondary offering of PrairieSky Royalty Ltd., coupled with major acquisitions in the top two oil plays in the U.S.; the Eagle Ford and the Permian Basin. These transactions have delivered a balanced liquids and natural gas portfolio and have made Encana more resilient to dynamic market conditions.

As Chairman of the Board, my focus is to continue our commitment to strong governance and corporate responsibility, while leading the Board of Directors in stewarding Encana towards building value for its shareholders. The Board of Directors continues to believe Encana’s strategy is the best way to grow profitability and maximize

shareholder value over the long term. With commodity prices expected to be volatile through 2015, the company will continue to make prudent decisions to ensure it emerges even stronger from this downturn.

On behalf of the Board of Directors, I’d like to thank Encana’s Executive Leadership Team and staff. Their achievements through 2014 have put the company in a position of relative strength and on a path to sustainable success.

LOGO

CLAYTON WOITAS

CHAIRMAN OF THE BOARD

LOGO

OPERATIONAL PERFORMANCE

In 2014 we met or exceeded all of our operational targets. We enhanced performance, executed a seamless entry into two new plays; the Eagle Ford and the Permian Basin, and delivered enduring efficiencies across the organization.

Safety

Delivered the lowest Total Recordable Injury Frequency in the history of Encana

$12.4 million

Average drilling and completion cost per well on Duvernay 4-4 pad (50% lower than 2013 average)

25% and 13%

Reduction in drilling and completion costs during our first three months operating in the Eagle Ford

$150 million

Total operating and administrative cost savings

34% to 29%

Reduction in base production decline rates

BALANCE SHEET STRENGTH

Maintaining a strong balance sheet and financial flexibility are fundamental to how we manage the company. In 2014, we transformed the portfolio without materially increasing debt.

$8 billion

Net proceeds from divestiture activity

$800 million

Divestitures announced in Q4 2014 with proceeds expected in Q1 2015

$400 million

Generated in free cash flow

Credit rating

Maintained investment grade credit rating

PORTFOLIO TRANSFORMATION

In 2014, we completed around $18 billion of acquisition and divestiture activity and built a balanced commodity portfolio, rich with investment opportunities in premium positions in Canada and the United States. We focused around 86 percent of our capital investment toward seven growth assets, down from nearly 30 assets the previous year.

Creating a focused, balanced and higher margin portfolio

We dramatically reshaped our portfolio and replaced lower margin natural gas production with higher margin liquids. We divested non-core assets and acquired two strategic assets in two of North America’s best oil plays.

LOGO

61 percent increase in liquids production

We grew total annual production from 54,000 bbls/d in 2013 to 87,000 bbls/d in 2014. Our five original growth assets; Montney, Duvernay, DJ Basin, San Juan and Tuscaloosa Marine Shale performed exceptionally. The acquisition of two new growth assets; in the Eagle Ford and the Permian Basin, made an immediate contribution to our liquids production.

LOGO

Shifting to higher value production

We are focused on high value production rather than production volume growth. In 2014, we delivered a 14 percent increase in year-over-year cash flow. We delivered this cash flow growth on approximately seven percent lower total production in a similar commodity price environment compared to 2013.

LOGO

Efficient, competitive and resilient

The transformation we undertook through 2014 occurred at a pace that surpassed our own high expectations. The result of our hard work is a competitive, resilient, low-cost and lean Encana. We have a focused portfolio rich with investment opportunities and premium positions in two of the best resource plays in Canada; the Montney and the Duvernay, and two of the best in the United States; the Eagle Ford and the Permian Basin.

The steps we took during 2014 were designed to deliver sustainable value to our shareholders by growing cash flow per share. We focused on higher value production rather than volume growth and directed our capital investment toward assets with scale and low supply costs – in short, the assets that provide the highest returns. This capital discipline was complemented by around $18 billion of acquisition and divestiture activity, which enabled us to dramatically reshape our portfolio and replace lower margin natural gas production with higher margin liquids.

Our cultural change has been just as dramatic and important to the transformation of the company. By embracing our values of One, Agile and Driven, our staff has harnessed the technical strength, knowledge and stability of a large organization, while adopting the mindset of a small, entrepreneurial company. They continue to relentlessly identify and implement ways to enhance efficiencies and streamline processes. In addition, in 2014 they delivered the best ever safety record in company history; an impressive accomplishment during a period of significant change.

The recent market volatility is a sharp reminder that we are in the commodity business. While we did not predict the recent drop in commodity prices, we knew that it was a possibility sometime during the execution of our long-term strategy.

With this in mind, our strategy was designed to create a competitive and resilient company able to deliver shareholder value through commodity price cycles.

While oil traded at approximately $100 per barrel, our staff delivered material efficiency improvements throughout the company. In a lower price environment, we see significant opportunity to deliver further enduring efficiencies.

We will continue to take a prudent view of commodity prices and will protect our balance sheet throughout 2015 by exercising strict financial discipline. Equally important, we will maintain a capital allocation philosophy that is consistent with our strategy by prioritizing investment to our four most strategic assets: the Eagle Ford, Permian Basin, Montney and Duvernay.

Our team’s accomplishments in 2014 should not be overshadowed by today’s low commodity environment. In fact, it makes their achievements even more important. We are in a position of relative strength with a culture and strategy that keep us on the path to becoming a leading North American resource play company.

On behalf of the Executive Leadership Team, I want to thank our Board of Directors for their ongoing support and say a special thank you to all Encana staff for a remarkable 2014.

LOGO

DOUG SUTTLES

PRESIDENT & CEO

LOGO


PILLARS
Encana is structured and organized around four core competencies that we believe every exploration and production company needs to excel at in order to deliver sustainable shareholder value.
TOP TIER ASSETS		CAPITAL ALLOCATION
We will always be on the lookout for the best rocks and focus our capital on a limited number of core growth assets characterized by high returns, scale and running room. Our strategy is centered on diversifying our commodity mix and growing value in top tier assets.		A highly disciplined, dynamic and centrally controlled capital allocation program will help ensure that we are directing our investment dollars in a manner that is consistent with our strategy. By concentrating capital on our core growth assets, we believe we can generate the most value for our shareholders.
MARKET FUNDAMENTALS		OPERATIONAL EXCELLENCE
We will actively monitor and manage the effects of market volatility to enable us to respond to the ever-changing trade winds inherent in the oil and gas business. Leveraging our industry-leading commodity market expertise to inform our capital allocation decisions is critical to both managing risk and maximizing margins.		Operational excellence is one of Encana’s strengths and we will continuously work to maintain this competitive advantage. We strive to increase profitability by running our operations in the most efficient and cost effective manner possible. Our best-in-class operators will focus on efficiency, safety and integrated and collaborative thinking in order to maximize value across our asset base.
BALANCE SHEET STRENGTH
Underpinning these four core competencies is balance sheet strength. Maintaining financial flexibility and investment grade credit ratings are an important part of how we think about managing our business. Balance sheet strength allows us to capitalize on opportunities as they arise and demonstrates the sustainability of our business model through commodity cycles.

FOCUSED INVESTMENT

Our portfolio is rich with high quality oil, natural gas liquids and natural gas investment opportunities. Around 80 percent of our 2015 capital program is expected to be focused on our four most strategic growth assets: the Eagle Ford, Permian Basin, Montney and Duvernay.

LOGO

FINANCIAL AND OPERATING PERFORMANCE

Year-end highlights

FINANCIAL HIGHLIGHTS ⁽¹⁾


(US$ millions, except per share amounts)	2014			2013
Revenues, Net of Royalties		8,019			5,858
Cash Flow ⁽²⁾		2,934			2,581
Per Share – Diluted		3.96			3.50
Net Earnings Attributable to Common Shareholders		3,392			236
Per Share – Diluted		4.58			0.32
Operating Earnings ⁽²⁾		1,002			802
Per Share – Diluted		1.35			1.09

Total Capital Investment		2,526			2,712
Net Acquisitions (Divestitures) ⁽³⁾		(1,329	)		(776	)
Net Capital Investment		1,197			1,936
Dividends Per Common Share		0.28			0.67
Dividend Yield (%) ⁽⁴⁾		2.0			3.7

Debt to Adjusted Capitalization (%) ⁽²⁾		30			36
Debt to Debt Adjusted Cash Flow ⁽²⁾		2.1			2.4
Debt to Proved Developed Reserves ($/BOE) ⁽⁵⁾⁽⁶⁾		8.63			6.66

(1)	Reported using financial information prepared in accordance with U.S. Generally Accepted Accounting Principles.

(2)	Non-GAAP measures as referenced in the Management’s Discussion & Analysis on pages 44 to 46.

(3)	2013 includes proceeds received from the sale of the Company’s 30 percent interest in the proposed Kitimat liquefied natural gas export terminal.

(4)	Based on NYSE closing price at year-end.

(5)	After royalties, employing forecast prices and costs.

(6)	A non-GAAP measure defined as long-term debt including current portion divided by proved developed reserve quantities.

OPERATIONAL HIGHLIGHTS


After Royalties	2014		2013
Production Volumes (average)
Natural Gas (MMcf/d)
Canadian Operations		1,378		1,432
USA Operations		972		1,345

Total Natural Gas (MMcf/d)		2,350		2,777

Oil & NGLs (Mbbls/d)
Canadian Operations		37.2		30.4
USA Operations		49.6		23.5

Total Oil & NGLs (Mbbls/d)		86.8		53.9

Reserves ⁽¹⁾
Natural Gas (Bcf)		5,522		8,576
Oil & NGLs (MMbbls)		356.5		234.9
Reserve Life Index (years)		7.3		8.8

For additional information on reserves reporting protocols, see page 41 and 48.

(1)	After royalties, employing forecast prices and costs.

Advisory

Encana reports in U.S. dollars unless otherwise noted. Production, sales, reserves and economic contingent resources estimates are reported on an after royalties basis, unless otherwise noted. Certain information regarding the company and its subsidiaries set forth in this document including management’s assessment of the company’s future plans and operations, may constitute forward-looking statements or forward-looking information under applicable securities laws and necessarily involve risks and uncertainties associated with future events. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements or information. For further details see the Advisory on page 46 of this document.

This document contains references to measures commonly referred to as non-GAAP measures, such as cash flow, cash flow per share – diluted, operating earnings, operating earnings per share – diluted, adjusted Cash Flow, debt to adjusted capitalization and debt to debt adjusted Cash Flow. Additional disclosure relating to these measures is set forth on page 44, Non-GAAP Measures.

LOGO

MANAGEMENT’S

DISCUSSION AND ANALYSIS

(Prepared using U.S. GAAP)

For the year ended December 31, 2014 (U.S. Dollars)

This Management’s Discussion and Analysis (“MD&A”) for Encana Corporation (“Encana” or the “Company”) should be read with the audited Consolidated Financial Statements for the year ended December 31, 2014 (“Consolidated Financial Statements”), as well as the audited Consolidated Financial Statements and MD&A for the year ended December 31, 2013.

The Consolidated Financial Statements and comparative information have been prepared in accordance with United States (“U.S.”) generally accepted accounting principles (“U.S. GAAP”) and in U.S. dollars, except where another currency has been indicated. References to C$ are to Canadian dollars. Encana’s financial results are consolidated in Canadian dollars; however, the Company has adopted the U.S. dollar as its reporting currency to facilitate a more direct comparison to other North American oil and gas companies. Production volumes are presented on an after royalties basis consistent with U.S. oil and

gas reporting standards and the disclosure of U.S. oil and gas companies. The term “liquids” is used to represent oil, natural gas liquids (“NGLs” or “NGL”) and condensate. The term “liquids rich” is used to represent natural gas streams with associated liquids volumes. This document is dated March 3, 2015.

For convenience, references in this document to “Encana”, the “Company”, “we”, “us”, “our” and “its” may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships (“Subsidiaries”) of Encana Corporation, and the assets, activities and initiatives of such Subsidiaries.

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. Non-GAAP 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: Cash Flow; Free Cash Flow; Operating Earnings; Upstream Operating Cash Flow, excluding Hedging; Operating Netback; Debt to Debt Adjusted Cash Flow; and Debt to Adjusted Capitalization. Further information regarding these measures can be found in the Non-GAAP Measures section of this MD&A, including reconciliations of Cash from Operating Activities to Cash Flow and Free Cash Flow, and of Net Earnings Attributable to Common Shareholders to Operating Earnings.

The following volumetric measures may be abbreviated throughout this MD&A: thousand cubic feet (“Mcf”); million cubic feet (“MMcf”) per day (“MMcf/d”); billion cubic feet (“Bcf”); trillion cubic feet (“Tcf”); barrel (“bbl”); thousand barrels (“Mbbls”) per day (“Mbbls/d”); million barrels (“MMbbls”); barrels of oil equivalent (“BOE”) per day (“BOE/d”); thousand barrels of oil equivalent (“MBOE”) per day (“MBOE/d”); million barrels of oil equivalent (“MMBOE”); million British thermal units (“MMBtu”).

Readers should also read the Advisory section located at the end of this document, which provides information on Forward-Looking Statements and Oil and Gas Information.

Management’s Discussion and Analysis

Financial Statements

12 /

Encana’s Strategic Objectives

32 /

Liquidity and Capital Resources

49 /

Management Report

12 /

Encana’s Business

35 /

Contractual Obligations and Contingencies

50 /

Auditor’s Report

13 /

Results Overview

36 /

Risk Management

52 /

Consolidated Financial Statements

19 /

Reserves Quantities

40 /

Controls and Procedures

56 /

Notes to Consolidated Financial Statements

22 /

Production Volumes

41 /

Accounting Policies and Estimates

104 /

Supplemental Information

24 /

Net Capital Investment

44 /

Non-GAAP Measures

27 /

Results of Operations

46 /

Advisory

27 /

Canadian Operations

29 /

USA Operations

31 /

Other Operating Results

LOGO

Annual Report 2014 | Encana Corporation 11

LOGO

ENCANA’S STRATEGIC OBJECTIVES

Encana is a leading North American energy producer that is focused on developing its strong portfolio of resource plays producing natural gas, oil and NGLs. 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 balancing its commodity portfolio, focusing capital investments in strategic high return scalable projects, maintaining portfolio flexibility to respond to changing market conditions, maximizing profitability through operating efficiencies, reducing costs and preserving balance sheet strength.

Encana continually strives to improve operating efficiencies, foster technological innovation and lower its cost structures, while reducing its environmental footprint through play optimization. The Company’s resource play hub model, which utilizes highly integrated production facilities, is used to develop resources by drilling multiple wells from central pad sites. Ongoing cost reductions are achieved through repeatable operations, optimizing equipment and processes and by applying continuous improvement techniques.

Encana hedges a portion of its expected natural gas and oil production volumes. The Company’s hedging program reduces volatility and helps sustain Cash Flow and operating netbacks during periods of lower prices. Further information on the Company’s commodity price positions as at December 31, 2014 can be found in the Results Overview section of this MD&A and in Note 23 to the Consolidated Financial Statements.

Additional information on expected results can be found in Encana’s 2015 Corporate Guidance on the Company’s website www.encana.com.

ENCANA’S BUSINESS

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

•

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

•

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

•

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

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.

12 Encana Corporation | Annual Report 2014

RESULTS OVERVIEW

HIGHLIGHTS

In the year ended December 31, 2014, Encana reported:

•

Cash Flow of $2,934 million, Operating Earnings of $1,002 million and Net Earnings Attributable to Common Shareholders of $3,392 million.

•

Average realized natural gas prices, including financial hedges, of $4.59 per Mcf. Average realized oil prices, including financial hedges, of $86.03 per bbl. Average realized NGL prices of $48.09 per bbl.

•

Average natural gas production volumes of 2,350 MMcf/d and average oil and NGL production volumes of 86.8 Mbbls/d.

•

Gain on divestitures of approximately $3.4 billion, before tax, primarily related to the sale of Encana’s investment in PrairieSky Royalty Ltd. (“PrairieSky”), the Company’s Bighorn assets and Jonah properties.

•

Dividends paid of $0.28 per share.

•

Long-term debt repayments and redemptions totaling approximately $2.5 billion, funded using cash on hand and proceeds of $1.3 billion drawn on the Company’s revolving credit facility.

•

Cash and cash equivalents of $338 million at year end.

Significant developments for the Company during the year ended December 31, 2014 included the following:

•

Completed the acquisition of all issued and outstanding shares of common stock of Athlon Energy Inc. (“Athlon”) for $5.93 billion, or $58.50 per share, on November 13, 2014. As part of the acquisition, Encana also assumed Athlon’s $1.15 billion senior notes and repaid and terminated Athlon’s credit facility with indebtedness outstanding of $335 million. Encana funded the acquisition with cash on hand. On December 16, 2014, Encana completed the redemption of Athlon’s senior notes. Athlon’s operations focused on the acquisition and development of oil and gas properties located in the Permian Basin in Texas.

•

Completed the secondary offering of 70.2 million common shares of PrairieSky on September 26, 2014 at a price of C$36.50 per common share for aggregate gross proceeds of approximately C$2.6 billion and recognized a gain on divestiture of approximately $2.1 billion, before tax. Following the completion of the secondary offering, Encana no longer holds an interest in PrairieSky.

During the second quarter of 2014, Encana completed the initial public offering of 59.8 million common shares of PrairieSky at a price of C$28.00 per common share for aggregate gross proceeds of approximately C$1.67 billion. Subsequent to the initial public offering, Encana owned 70.2 million common shares of PrairieSky, representing a 54 percent ownership interest.

•

Completed the acquisition of certain properties in the Eagle Ford shale formation in south Texas (“Eagle Ford”) on June 20, 2014 for approximately $2.9 billion, after closing adjustments. The transaction had an effective date of April 1, 2014.

•

Closed the sale of the Company’s Bighorn assets located in west central Alberta on September 30, 2014 for approximately $1.7 billion, after closing adjustments, and recognized a gain on divestiture of approximately $1.0 billion, before tax. The transaction had an effective date of May 1, 2014.

•

Closed the sale of the Jonah properties in Wyoming on May 12, 2014 for proceeds of approximately $1.6 billion, after closing adjustments, and recognized a gain on divestiture of approximately $209 million, before tax.

•

Closed the majority of the sale of certain properties in East Texas on June 19, 2014 for proceeds of approximately $425 million and closed the balance of the transaction on September 30, 2014 for proceeds of approximately $70 million.

•

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

•

Announced an agreement with Ember Resources Inc. to sell certain Clearwater assets located in central and southern Alberta on October 8, 2014. The sale includes the Company’s working interest in approximately 1.2 million net acres of land and over 6,800 producing wells. Encana retains a working interest in approximately 1.1 million net acres in Clearwater. The sale closed on January 15, 2015 and proceeds of approximately C$556 million, after closing adjustments, were received.

•

Announced an agreement with Veresen Midstream Limited Partnership on December 22, 2014 to sell certain natural gas gathering and compression assets in northeastern British Columbia for approximately C$412 million in cash consideration net to Encana. The transaction is expected to close in the first quarter of 2015, subject to regulatory approval and the satisfaction of normal closing conditions.

As a result of the execution of the strategy announced in November 2013, the Company’s results for the year ended December 31, 2014 reflected the following:

•

Acquired properties in Eagle Ford and the Permian Basin, which provide significant oil reserves to the Company.

•

Divested natural gas-weighted properties in Jonah, East Texas and Bighorn.

•

Completed the initial public offering and secondary offering of common shares of PrairieSky, providing a source of funding for subsequent acquisition transactions.

•

Focused capital spending on seven growth assets, totaling approximately $2.2 billion, or 86 percent of total capital investment.

•

Reported oil and NGL production volumes of 86.8 Mbbls/d, an increase of 61 percent from 2013. Average oil and NGL production volumes were 18 percent of total production in 2014 compared to 10 percent in 2013.

•

Achieved total operating and administrative cost savings of approximately $150 million attributable to workforce reductions and operating efficiencies, of which approximately $45 million is reflected in operating expense, $35 million in administrative expense and $70 million in capital costs.

LOGO

Annual Report 2014 | Encana Corporation 13

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FINANCIAL RESULTS


	2014															2013															2012
($ millions, except as indicated)	Annual			Q4			Q3			Q2			Q1			Annual			Q4			Q3			Q2			Q1			Annual

Cash Flow ⁽¹⁾	$	2,934		$	377		$	807		$	656		$	1,094		$	2,581		$	677		$	660		$	665		$	579		$	3,537

$ per share - diluted		3.96			0.51			1.09			0.89			1.48			3.50			0.91			0.89			0.90			0.79			4.80

Operating Earnings ⁽¹⁾		1,002			35			281			171			515			802			226			150			247			179			997

$ per share - diluted		1.35			0.05			0.38			0.23			0.70			1.09			0.31			0.20			0.34			0.24			1.35

Net Earnings (Loss) Attributable to Common Shareholders		3,392			198			2,807			271			116			236			(251	)		188			730			(431	)		(2,794	)

$ per share - basic & diluted		4.58			0.27			3.79			0.37			0.16			0.32			(0.34	)		0.25			0.99			(0.59	)		(3.79	)


Revenues, Net of Royalties		8,019			2,254			2,285			1,588			1,892			5,858			1,423			1,392			1,984			1,059			5,160

Realized Hedging Gain (Loss), before tax		(91	)		124			28			(102	)		(141	)		544			174			175			52			143			2,161

Unrealized Hedging Gain (Loss), before tax		444			489			231			9			(285	)		(345	)		(301	)		(128	)		469			(385	)		(1,465	)

Upstream Operating Cash Flow		3,918			821			982			800			1,315			3,192			901			794			788			709			4,084

Upstream Operating Cash Flow Excluding Realized Hedging ⁽¹⁾		3,999			694			952			898			1,455			2,652			728			622			737			565			1,931


Capital Investment		2,526			857			598			560			511			2,712			717			641			639			715			3,476

Net Acquisitions & (Divestitures) ⁽²⁾		(1,329	)		50			(2,007	)		652			(24	)		(521	)		(72	)		(51	)		(312	)		(86	)		(3,664	)

Free Cash Flow ⁽¹⁾		408			(480	)		209			96			583			(131	)		(40	)		19			26			(136	)		61

Ceiling Test Impairments, after tax		—			—			—			—			—			—			—			—			—			—			(3,179	)

Gain (Loss) on Divestitures, after tax		2,523			(11	)		2,399			135			—			—			—			—			—			—			—


Total Assets		24,621															17,648															18,700

Total Debt		7,340															7,124															7,675

Cash & Cash Equivalents		338															2,566															3,179


Production Volumes

Natural Gas (MMcf/d)		2,350			1,861			2,199			2,541			2,809			2,777			2,744			2,723			2,766			2,877			2,981

Oil & NGLs (Mbbls/d)
Oil		49.4			68.8			62.1			34.2			32.1			25.8			33.0			27.2			22.9			20.0			17.6
NGLs		37.4			37.6			41.9			34.0			35.8			28.1			33.0			31.0			24.7			23.5			13.4
Total Oil & NGLs		86.8			106.4			104.0			68.2			67.9			53.9			66.0			58.2			47.6			43.5			31.0

Total Production (MBOE/d)		478.5			416.7			470.6			491.8			536.1			516.7			523.4			512.1			508.6			523.0			527.9

Production Mix (%)

Natural Gas		82			74			78			86			87			90			87			89			91			92			94

Oil & NGLs		18			26			22			14			13			10			13			11			9			8			6

(1)	A non-GAAP measure, which is defined under the Non-GAAP Measures section of this MD&A.

(2)	Excluding the impact of the PrairieSky divestiture and Athlon acquisition as discussed in the Net Capital Investment section of this MD&A.

14 Encana Corporation | Annual Report 2014

Encana’s quarterly net earnings can be significantly impacted by fluctuations in commodity prices, realized and unrealized hedging gains and losses, production volumes, foreign exchange rates, non-cash ceiling test impairments and gains or losses on divestitures, which are provided in the Financial Results table and Prices and Foreign Exchange Rates table within this MD&A. Quarterly net earnings are also impacted by Encana’s interim income tax expense calculated using the estimated annual effective income tax rate as discussed in the Critical Accounting Estimates section of this MD&A. Quarterly net earnings are also impacted by acquisition and divestiture transactions, which are discussed in the Net Capital Investment section of this MD&A.

Under full cost accounting, the carrying amount of Encana’s natural gas and oil properties within each country cost centre is subject to a ceiling test performed quarterly. Ceiling test impairments are recognized when the capitalized costs exceed the sum of the estimated after-tax future net cash flows from proved reserves as calculated under Securities and Exchange Commission (“SEC”) requirements using the 12-month average trailing prices and discounted at 10 percent. The Company’s after-tax non-cash ceiling test impairment in 2012 primarily resulted from the decline in the 12-month average trailing natural gas prices.

In the last half of 2014, commodity prices have generally declined. Further declines in the 12-month average trailing commodity prices could reduce proved reserves values and result in the recognition of future ceiling test impairments. Future ceiling test impairments can also result from changes to reserves estimates, future development costs, capitalized costs and unproved property costs. Proceeds received from oil and gas divestitures are generally deducted from the Company’s capitalized costs and can reduce the risk of ceiling test impairments.

Q4 2014 versus Q4 2013

Cash Flow of $377 million decreased $300 million in the three months ended December 31, 2014 primarily due to the following significant items:

•

Average realized natural gas prices, excluding financial hedges, were $3.94 per Mcf compared to $3.69 per Mcf in 2013 reflecting higher benchmark prices for AECO and NYMEX. Higher realized natural gas prices increased revenues $44 million. Average realized liquids prices, excluding financial hedges, were $57.35 per bbl compared to $65.58 per bbl in 2013 reflecting lower benchmark prices. Lower realized liquids prices decreased revenues $105 million.

•

Average natural gas production volumes of 1,861 MMcf/d decreased 883 MMcf/d from 2,744 MMcf/d in 2013 primarily due to divestitures resulting from the Company’s strategic transition to a more balanced commodity portfolio and natural declines. Lower natural gas volumes decreased revenues $303 million. Average oil and NGL production volumes of 106.4 Mbbls/d increased 40.4 Mbbls/d from 66.0 Mbbls/d in 2013 primarily due to acquisitions and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures and the sale of the Company’s investment in PrairieSky. Higher oil and NGL volumes increased revenues $267 million.

•

Realized financial hedging gains before tax were $124 million compared to $174 million in 2013.

•

Transportation and processing expense decreased $49 million primarily due to divestitures and the lower U.S./Canadian dollar exchange rate, partially offset by higher liquids volumes processed.

•

Administrative expense decreased $109 million primarily due to lower restructuring charges of $68 million. The decrease also reflects lower non-cash long-term compensation costs resulting from the decrease in the Encana share price.

•

Interest expense increased $113 million primarily due to a one-time outlay associated with the early redemption of senior notes assumed in conjunction with the acquisition of Athlon.

•

Other expense increased $56 million primarily due to transaction costs of $31 million associated with the acquisition of Athlon. The increase also reflects non-cash reclamation charges relating to non-producing assets.

•

Current tax expense was $2 million compared to a recovery of $25 million in 2013. Cash Flow excludes cash tax on the sale of assets as discussed in the Non-GAAP Measures section of this MD&A.

Operating Earnings of $35 million decreased $191 million primarily due to the items discussed in the Cash Flow section. Operating Earnings for the fourth quarter of 2014 were also impacted by higher depreciation, depletion and amortization (“DD&A”), a foreign exchange gain on the revaluation of other monetary assets, lower long-term compensation costs and deferred tax. Operating Earnings excludes restructuring charges as described in the Non-GAAP Measures section of this MD&A.

Net Earnings Attributable to Common Shareholders of $198 million increased $449 million primarily due to unrealized hedging gains and the items discussed in the Cash Flow and Operating Earnings sections. Net Earnings Attributable to Common Shareholders for the fourth quarter of 2014 were also impacted by deferred tax.

2014 versus 2013

Cash Flow of $2,934 million increased $353 million in the year ended December 31, 2014 primarily due to the following significant items:

•

Average realized natural gas prices, excluding financial hedges, were $4.78 per Mcf compared to $3.57 per Mcf in 2013 reflecting higher benchmark prices, including the impact of higher realized prices from Deep Panuke production. Higher realized natural gas prices increased revenues $1,067 million. Average realized liquids prices, excluding financial hedges, were $67.24 per bbl compared to $67.30 per bbl in 2013 reflecting lower WTI prices. Lower realized liquids prices decreased revenues $23 million.

•

Average natural gas production volumes of 2,350 MMcf/d decreased 427 MMcf/d from 2,777 MMcf/d in 2013 primarily due to divestitures resulting from the Company’s strategic transition to a more balanced commodity portfolio and natural declines, partially offset by production from Deep Panuke. Lower natural gas volumes decreased revenues $602 million. Average oil and NGL production volumes of 86.8 Mbbls/d increased 32.9 Mbbls/d from 53.9 Mbbls/d in 2013 primarily due to acquisitions and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures and the sale of the Company’s investment in PrairieSky. Higher oil and NGL volumes increased revenues $829 million.

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Annual Report 2014 | Encana Corporation 15

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•

Realized financial hedging losses before tax were $91 million compared to gains of $544 million in 2013.

•

Operating expense decreased $124 million primarily due to lower salaries and benefits related to workforce reductions resulting from the 2013 restructuring, divestitures and the lower U.S./Canadian dollar exchange rate, partially offset by acquisitions. The decrease also reflects lower non-cash long-term compensation costs resulting from the decrease in the Encana share price.

•

Administrative expense decreased $112 million primarily due to lower restructuring charges of $52 million and the lower U.S./Canadian dollar exchange rate. The decrease also reflects lower non-cash long-term compensation costs resulting from the decrease in the Encana share price.

•

Interest expense increased $91 million primarily due to a one-time outlay associated with the early redemption of senior notes assumed in conjunction with the acquisition of Athlon.

•

Other expense increased $70 million primarily due to transaction costs of $40 million associated with the acquisitions of Athlon and Eagle Ford. The increase also reflects non-cash reclamation charges relating to non-producing assets.

•

Current tax expense was $243 million compared to a recovery of $191 million in 2013 as discussed in the Other Operating Results section of this MD&A. Cash Flow excludes cash tax on the sale of assets as discussed in the Non-GAAP Measures section of this MD&A.

Operating Earnings of $1,002 million increased $200 million primarily due to the items discussed in the Cash Flow section. Operating Earnings for 2014 were also impacted by a higher foreign exchange gain on the revaluation of other monetary assets and higher DD&A. Operating Earnings excludes restructuring charges as described in the Non-GAAP Measures section of this MD&A.

Net Earnings Attributable to Common Shareholders of $3,392 million increased $3,156 million primarily due to gains on divestitures as well as the items discussed in the Cash Flow and Operating Earnings sections. Net Earnings Attributable to Common Shareholders for 2014 were also impacted by unrealized hedging gains, a higher after-tax non-operating foreign exchange loss and deferred tax.

2013 versus 2012

Cash Flow of $2,581 million decreased $956 million in the year ended December 31, 2013 primarily due to the following significant items:

•

Average realized natural gas prices, excluding financial hedges, were $3.57 per Mcf compared to $2.83 per Mcf in 2012 reflecting higher benchmark prices which increased revenues $790 million. Average realized liquids prices, excluding hedges, were $67.30 per bbl compared to $75.12 per bbl in 2012 which decreased revenues $168 million.

•

Average natural gas production volumes of 2,777 MMcf/d decreased 204 MMcf/d from 2,981 MMcf/d in 2012 primarily due to the Company’s capital investment focus in oil and liquids rich natural gas plays, a reduced capital investment program and natural declines, partially offset by shut-in production volumes in 2012, successful drilling programs and production from the Deep Panuke offshore natural gas facility in 2013. Lower natural gas volumes decreased revenues $208 million. Average oil and NGL production volumes of 53.9 Mbbls/d increased 22.9 Mbbls/d from 31.0 Mbbls/d in 2012 primarily due to successful drilling programs in oil and liquids rich natural gas plays, the extraction of additional liquids volumes processed through third party facilities and additional NGL volumes resulting from new and renegotiated gathering and processing agreements. Higher oil and NGL volumes increased revenues $640 million.

•

Realized financial hedging gains before tax were $544 million compared to $2,161 million in 2012.

•

Transportation and processing expense increased $245 million primarily due to costs related to higher production volumes processed through third party facilities, additional NGL volumes resulting from new and renegotiated gathering and processing agreements, costs related to the Deep Panuke offshore natural gas facility and higher firm processing costs.

•

Operating expense increased $65 million primarily due to an increased focus on emerging oil and liquids rich natural gas plays.

•

Administrative expense increased primarily due to restructuring charges as discussed in the Other Operating Results section of this MD&A.

Operating Earnings of $802 million decreased $195 million primarily due to the items discussed in the Cash Flow section, partially offset by lower DD&A and lower deferred tax. Operating Earnings excludes restructuring charges as described in the Non-GAAP Measures section of this MD&A.

Net Earnings were $236 million compared to a Net Loss of $2,794 million in 2012 primarily due to the inclusion of after-tax non-cash ceiling test impairments of $3,179 million in the 2012 comparative, partially offset by the items discussed in the Cash Flow and Operating Earnings sections. Net Earnings for 2013 were also impacted by lower unrealized hedging losses of $770 million after tax, partially offset by an after-tax non-operating foreign exchange loss and higher administrative expense as a result of restructuring charges.

16 Encana Corporation | Annual Report 2014

PRICES AND FOREIGN EXCHANGE RATES


	2014										2013										2012
(average for the period)	Annual		Q4		Q3		Q2		Q1		Annual		Q4		Q3		Q2		Q1		Annual
Encana Realized Pricing
Including Hedging
Natural Gas ($/Mcf)	$	4.59	$	4.16	$	4.03	$	4.08	$	5.82	$	4.09	$	4.34	$	4.00	$	4.17	$	3.86	$	4.82
Oil & NGLs ($/bbl)
Oil		86.03		80.38		90.22		89.55		86.34		88.19		85.39		90.42		88.27		89.71		84.06
NGLs		48.09		40.87		48.76		49.39		53.79		48.95		48.59		46.35		49.63		52.24		63.37
Total Oil & NGLs		69.70		66.40		73.50		69.53		69.19		67.75		67.01		66.95		68.25		69.45		75.12
Total ($/BOE)		35.21		35.55		35.06		30.75		39.22		29.05		31.23		28.85		29.08		27.00		31.62
Excluding Hedging
Natural Gas ($/Mcf)		4.78		3.94		3.88		4.46		6.37		3.57		3.69		3.26		3.99		3.35		2.83
Oil & NGLs ($/bbl)
Oil		81.71		66.38		90.18		92.93		86.43		87.25		82.54		96.09		85.89		84.46		84.06
NGLs		48.09		40.87		48.76		49.39		53.79		48.95		48.59		46.35		49.63		52.24		63.37
Total Oil & NGLs		67.24		57.35		73.48		71.23		69.23		67.30		65.58		69.60		67.10		67.04		75.12
Total ($/BOE)		35.67		32.25		34.36		32.93		42.12		26.20		27.63		25.23		27.99		23.97		20.40
Natural Gas Price Benchmarks
NYMEX ($/MMBtu)		4.41		4.00		4.06		4.67		4.94		3.65		3.60		3.58		4.09		3.34		2.79
AECO (C$/Mcf)		4.42		4.01		4.22		4.68		4.76		3.16		3.15		2.82		3.59		3.08		2.40
Algonquin City Gate ($/MMBtu) ⁽¹⁾		8.06		4.99		2.97		4.23		20.28		6.97		7.80		3.98		4.63		11.56		3.94
Basis Differential ($/MMBtu)
AECO/NYMEX		0.39		0.44		0.16		0.40		0.60		0.57		0.59		0.89		0.56		0.27		0.38
Oil Price Benchmarks
West Texas Intermediate (WTI) ($/bbl)		93.00		73.15		97.17		102.99		98.68		97.97		97.46		105.81		94.17		94.36		94.21
Edmonton Light Sweet (C$/bbl)		94.57		75.69		97.16		105.61		99.83		93.11		86.58		103.65		92.67		87.43		87.02
Foreign Exchange
Average U.S./Canadian Dollar Exchange Rate		0.905		0.881		0.918		0.917		0.906		0.971		0.953		0.963		0.977		0.992		1.000

(1)	The Algonquin City Gate benchmark reflects the daily average price for sales of production from Atlantic Canada. Encana’s operations at Deep Panuke in Atlantic Canada commenced in Q4 2013.

Encana’s financial results are influenced by fluctuations in commodity prices, price differentials and the U.S./Canadian dollar exchange rate. In 2014, Encana’s average realized natural gas price, excluding hedging, reflected higher benchmark prices compared to 2013. Hedging activities reduced Encana’s average realized natural gas price $0.19 per Mcf in 2014. Realized natural gas prices for production from Deep Panuke were $8.34 per Mcf in 2014, which increased Encana’s average realized natural gas price $0.31 per Mcf in 2014. The Deep Panuke offshore natural gas facility commenced commercial operations in December 2013.

In 2014, Encana’s average realized oil price, excluding hedging, reflected generally lower benchmark prices compared to 2013. Hedging activities contributed $4.32 per bbl to Encana’s average realized oil price in 2014.

In 2013, Encana’s average realized natural gas price, excluding hedging, reflected higher benchmark prices compared to 2012. Hedging activities contributed $0.52 per Mcf to the average realized natural gas price in 2013. Encana’s average realized oil price, excluding hedging for 2013, reflected higher benchmark prices. Hedging activities contributed $0.94 per bbl to the average realized oil price in 2013. The Company’s 2013 NGLs price reflected a lower proportion of higher value condensate included in the total NGL product mix.

As a means of managing commodity price volatility and its impact on cash flows, Encana enters into various financial hedge agreements. Unsettled derivative financial contracts are recorded at the date of the financial statements based on the fair value of the contracts. Changes in fair value result from volatility in forward curves of commodity prices and changes in the balance of unsettled contracts between periods. The changes in fair value are recognized in revenue as unrealized hedging gains and losses. Realized hedging gains and losses are recognized in revenue when derivative financial contracts are settled.

At December 31, 2014, Encana has hedged approximately 1,062 MMcf/d of expected 2015 natural gas production using NYMEX fixed price contracts at an average price of $4.29 per Mcf. In addition, Encana has hedged approximately 12.3 Mbbls/d of expected 2015 oil production using WTI fixed price contracts at an average price of $92.88 per bbl and approximately 1.2 Mbbls/d of expected 2016 oil production at an average price of $92.35 per bbl. At February 24, 2015, Encana has hedged approximately 1,044 MMcf/d of expected February to December 2015 natural gas production using NYMEX fixed price contracts at an average price of $4.29 per Mcf. In addition, Encana has hedged approximately 55.3 Mbbls/d of expected February to December 2015 oil production using WTI fixed price contracts at an average price of $62.18 per bbl and approximately 1.2 Mbbls/d of expected 2016 oil production at an average price of $92.35 per bbl.

The Company’s hedging program helps sustain Cash Flow and operating netbacks during periods of lower prices. For additional information, see the Risk Management – Financial Risks section of this MD&A.

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FOREIGN EXCHANGE

As disclosed in the Prices and Foreign Exchange Rates table, the average U.S./Canadian dollar exchange rate decreased 0.066 in 2014 compared to 2013 and 0.029 in 2013 compared to 2012. The table below summarizes selected foreign exchange impacts on Encana’s financial results when compared to the same periods in the prior years.


	2014						2013						2012
	$ millions			$/BOE			$ millions			$/BOE			$ millions			$/BOE
Increase (Decrease) in:
Capital Investment	$	(100	)				$	(45	)				$	(18	)
Transportation and Processing Expense		(51	)	$	(0.29	)		(17	)	$	(0.09	)		(5	)	$	(0.03	)
Operating Expense		(25	)		(0.14	)		(10	)		(0.05	)		(3	)		(0.02	)
Administrative Expense		(23	)		(0.13	)		(12	)		(0.06	)		(3	)		(0.02	)
Depreciation, Depletion and Amortization		(41	)		(0.23	)		(23	)		(0.10	)		(8	)		(0.04	)

PRICE SENSITIVITIES

Natural gas and liquids prices fluctuate in response to changing market forces, creating varying impacts on Encana’s financial results. The Company’s potential exposure to commodity price fluctuations is summarized in the table below, which shows the estimated effects that certain price changes would have had on the Company’s Cash Flow and Operating Earnings for 2014. The price sensitivities below are based on business conditions, transactions and production volumes during 2014. Accordingly, these sensitivities may not be indicative of financial results for other periods, under other economic circumstances or with additional fluctuations in commodity prices.

Impact On

($ millions, except as indicated)

Price Change ⁽¹⁾

Cash Flow

Operating Earnings

Increase or Decrease in:

NYMEX Natural Gas Price

+/- $

0.50/Mcf

WTI Oil Price

+/- $

10.00/bbl

121

(1)	Assumes only one variable changes while all other variables are held constant.

18 Encana Corporation | Annual Report 2014

RESERVES QUANTITIES

Since its formation in 2002, Encana has retained independent qualified reserves evaluators (“IQREs”) to evaluate and prepare reports on 100 percent of the Company’s natural gas, oil and NGL reserves annually. The Company has a Reserves Committee composed of independent Board of Directors (“Board”) members that reviews the qualifications and appointment of the IQREs. The Reserves Committee also reviews the procedures for providing information to the IQREs. All booked reserves are based upon annual evaluations by the IQREs.

As required by Canadian regulatory standards, Encana’s disclosure of reserves data is in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Encana’s 2014 Canadian protocol disclosure includes proved reserves quantities before and after royalties employing forecast prices and costs and is available in Encana’s Annual Information Form (“AIF”). Canadian standards require reconciliations in this section to include barrels of oil equivalent. The natural gas volumes have been converted to barrels of oil equivalent on the basis of six Mcf to one bbl based on an energy equivalency conversion method primarily applicable at the burner tip. This energy equivalency conversion method does not represent value equivalency, as the current price of oil and NGLs compared to natural gas is significantly higher.

Supplementary oil and gas information, including proved reserves on an after royalties basis, is provided in accordance with U.S. disclosure requirements in Note 26 to the December 31, 2014 Consolidated Financial Statements. As Encana follows U.S. GAAP full cost accounting for oil and gas activities, the U.S. protocol reserves estimates are key inputs to the Company’s depletion and ceiling test impairment calculations.

The Canadian standards require the use of forecast prices in the estimation of reserves and the disclosure of before and after royalties volumes. The U.S. standards require the use of 12-month average trailing prices in the estimation of reserves and the disclosure of after royalties volumes. The following sections provide Encana’s Canadian protocol and U.S. protocol reserves quantities.

CANADIAN PROTOCOL RESERVES QUANTITIES

PROVED RESERVES BY COUNTRY ⁽¹⁾

(FORECAST PRICES AND COSTS; BEFORE ROYALTIES)


	Natural Gas (Bcf)						Oil & NGLs (MMbbls)
(as at December 31)	2014		2013		2012		2014		2013		2012
Canada		3,752		5,031		6,730		97.2		141.1		126.3
United States		2,712		4,887		6,660		357.6		136.2		156.2

Total		6,463		9,918		13,390		454.7		277.3		282.5

(1)	Numbers may not add due to rounding.

PROVED RESERVES RECONCILIATION ⁽¹⁾

(FORECAST PRICES AND COSTS; BEFORE ROYALTIES)


	Natural Gas (Bcf)									Oil & NGLs (MMbbls)									Total (MMBOE)
	Canada			United States			Total			Canada			United States			Total			Total (MMBOE)
December 31, 2013		5,031			4,887			9,918			141.1			136.2			277.3			1,930.3
Extensions and improved recovery		391			594			986			27.3			30.0			57.3			221.6
Discoveries		28			—			28			4.7			—			4.7			9.4
Technical revisions		(171	)		(662	)		(833	)		(5.7	)		(0.1	)		(5.7	)		(144.6	)
Economic factors		(58	)		(69	)		(127	)		(0.5	)		(1.4	)		(1.9	)		(23.1	)
Acquisitions		7			300			307			0.1			257.7			257.8			309.0
Dispositions		(932	)		(1,903	)		(2,835	)		(56.6	)		(42.4	)		(99.0	)		(571.5	)
Production		(544	)		(436	)		(980	)		(13.2	)		(22.5	)		(35.7	)		(199.0	)

December 31, 2014		3,752			2,712			6,463			97.2			357.6			454.7			1,532.0

(1)	Numbers may not add due to rounding.

Encana’s 2014 proved natural gas reserves before royalties of approximately 6.5 Tcf decreased 3.5 Tcf from 2013 primarily due to dispositions of approximately 2.8 Tcf resulting from the Company’s strategic transition to a more balanced commodity portfolio. Extensions and improved recovery and discoveries of approximately 1.0 Tcf were mostly offset by negative technical revisions of approximately 0.8 Tcf primarily due to revised development plans. Extensions and improved recovery and discoveries replaced 103 percent of production before royalties during the year.

Encana’s 2014 proved oil and NGL reserves before royalties of approximately 454.7 MMbbls increased 177.4 MMbbls from 2013 primarily due to acquisitions of approximately 257.8 MMbbls, partially offset by dispositions of approximately 99.0 MMbbls resulting from the Company’s strategic transition to a more balanced commodity portfolio. Extensions and improved recovery and discoveries of approximately 62.0 MMbbls replaced 174 percent of production before royalties during the year.

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PROVED RESERVES BY COUNTRY ⁽¹⁾

(FORECAST PRICES AND COSTS; AFTER ROYALTIES)


	Natural Gas (Bcf)						Oil & NGLs (MMbbls)
(as at December 31)	2014		2013		2012		2014		2013		2012
Canada		3,252		4,550		6,207		76.2		122.2		113.1
United States		2,270		4,026		5,410		280.3		112.7		127.3

Total		5,522		8,576		11,617		356.5		234.9		240.4

(1)	Numbers may not add due to rounding.

PROVED RESERVES RECONCILIATION ⁽¹⁾

(FORECAST PRICES AND COSTS; AFTER ROYALTIES)


	Natural Gas (Bcf)									Oil & NGLs (MMbbls)
	Canada			United States			Total			Canada			United States			Total			Total (MMBOE)
December 31, 2013		4,550			4,026			8,576			122.2			112.7			234.9			1,664.2
Extensions and discoveries		371			475			847			25.4			24.4			49.7			190.8
Revisions ⁽²⁾		(233	)		(619	)		(852	)		(2.8	)		(1.8	)		(4.6	)		(146.6	)
Acquisitions		6			231			237			0.1			198.0			198.1			237.5
Dispositions		(938	)		(1,488	)		(2,427	)		(55.1	)		(34.8	)		(89.9	)		(494.3	)
Production		(503	)		(355	)		(858	)		(13.6	)		(18.1	)		(31.7	)		(174.6	)

December 31, 2014		3,252			2,270			5,522			76.2			280.3			356.5			1,276.9

(1)	Numbers may not add due to rounding.

(2)	Includes economic factors.

Encana’s 2014 proved natural gas reserves after royalties of approximately 5.5 Tcf decreased 3.1 Tcf from 2013 primarily due to dispositions of approximately 2.4 Tcf resulting from the Company’s strategic transition to a more balanced commodity portfolio. Negative revisions of approximately 0.9 Tcf were mainly due to revised development plans and were offset by extensions and discoveries of approximately 0.8 Tcf. Extensions and discoveries replaced 99 percent of production after royalties during the year.

Encana’s 2014 proved oil and NGL reserves after royalties of approximately 356.5 MMbbls increased 121.6 MMbbls from 2013 primarily due to acquisitions of approximately 198.1 MMbbls, partially offset by dispositions of approximately 89.9 MMbbls resulting from the Company’s strategic transition to a more balanced commodity portfolio. Extensions and discoveries of approximately 49.7 MMbbls replaced 157 percent of production after royalties during the year.

FORECAST PRICES

The reference prices below were utilized in the determination of reserves.


	Natural Gas				Oil & NGLs
	Henry Hub ($/MMBtu)		AECO (C$/MMBtu)		WTI ($/bbl)		Edmonton Light Sweet (C$/bbl)
2012 Price Assumptions
2013		3.75		3.38		90.00		85.00
2014 - 2022		4.25 - 6.27		3.83 - 5.64		92.50 - 104.57		91.50 - 103.57
Thereafter		+2%/yr		+2%/yr		+2%/yr		+2%/yr

2013 Price Assumptions
2014		4.25		4.03		97.50		92.76
2015 - 2023		4.50 - 5.97		4.26 - 5.66		97.50 - 104.57		97.37 - 106.93
Thereafter		+2%/yr		+2%/yr		+2%/yr		+2%/yr

2014 Price Assumptions
2015		3.31		3.31		62.50		64.71
2016 - 2024		3.75 - 5.68		3.77 - 5.71		75.00 - 104.57		80.00 - 112.67
Thereafter		+2%/yr		+2%/yr		+2%/yr		+2%/yr

20 Encana Corporation | Annual Report 2014

U.S. PROTOCOL RESERVES QUANTITIES

PROVED RESERVES BY COUNTRY ⁽¹⁾

(12-MONTH AVERAGE TRAILING PRICES; AFTER ROYALTIES)


	Natural Gas (Bcf)						Oil & NGLs (MMbbls)
(as at December 31)	2014		2013		2012		2014		2013		2012
Canada		3,229		3,975		4,550		77.5		110.2		101.6
United States		2,265		3,877		4,242		284.3		110.6		108.4

Total		5,494		7,852		8,792		361.7		220.8		210.0

(1)	Numbers may not add due to rounding.

PROVED RESERVES RECONCILIATION ⁽¹⁾

(12-MONTH AVERAGE TRAILING PRICES; AFTER ROYALTIES)


	Natural Gas (Bcf)									Oil & NGLs (MMbbls)
	Canada			United States			Total			Canada			United States			Total
December 31, 2013		3,975			3,877			7,852			110.2			110.6			220.8
Revisions and improved recovery		250			(511	)		(261	)		5.9			(5.3	)		0.5
Extensions and discoveries		385			493			879			27.0			30.2			57.2
Purchase of reserves in place		6			234			240			0.1			201.0			201.1
Sale of reserves in place		(885	)		(1,473	)		(2,358	)		(52.1	)		(34.1	)		(86.2	)
Production		(503	)		(355	)		(858	)		(13.6	)		(18.1	)		(31.7	)

December 31, 2014		3,229			2,265			5,494			77.5			284.3			361.7

(1)	Numbers may not add due to rounding.

Encana’s 2014 proved natural gas reserves after royalties of approximately 5.5 Tcf decreased 2.4 Tcf from 2013 primarily due to the sale of reserves in place of approximately 2.4 Tcf resulting from the Company’s strategic transition to a more balanced commodity portfolio. Extensions and discoveries of approximately 0.9 Tcf replaced 102 percent of production after royalties during the year.

Encana’s 2014 proved oil and NGL reserves after royalties of approximately 361.7 MMbbls increased 140.9 MMbbls from 2013 primarily due to the purchase of reserves in place of approximately 201.1 MMbbls, partially offset by the sale of reserves in place of approximately 86.2 MMbbls resulting from the Company’s strategic transition to a more balanced commodity portfolio. Extensions and discoveries of approximately 57.2 MMbbls replaced 180 percent of production after royalties during the year.

12-MONTH AVERAGE TRAILING PRICES

The reference prices below were utilized in the determination of reserves. The 12-month average trailing price is calculated as the average of the prices on the first day of each month within the trailing 12-month period.


	Natural Gas				Oil & NGLs
	Henry Hub ($/MMBtu)		AECO (C$/MMBtu)		WTI ($/bbl)		Edmonton Light Sweet (C$/bbl)
Reserves Pricing ⁽¹⁾
2012		2.76		2.35		94.71		87.42
2013		3.67		3.14		96.94		93.44
2014		4.34		4.63		94.99		96.40

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

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Annual Report 2014 | Encana Corporation 21

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PRODUCTION VOLUMES


(average daily, after royalties)	2014		2013		2012
Natural Gas (MMcf/d)		2,350		2,777		2,981
Oil (Mbbls/d)		49.4		25.8		17.6
NGLs (Mbbls/d)		37.4		28.1		13.4

Total Oil & NGLs (Mbbls/d)		86.8		53.9		31.0

Total Production (MBOE/d)		478.5		516.7		527.9

Production Mix (%)
Natural Gas		82		90		94
Oil & NGLs		18		10		6

PRODUCTION VOLUMES BY PLAY


(average daily, after royalties)	Natural Gas (MMcf/d)						Oil & NGLs (Mbbls/d)
	2014		2013		2012		2014		2013		2012
Canadian Operations
Montney		514		463		404		18.7		10.0		3.9
Duvernay		11		4		1		2.1		0.7		0.2
Other Upstream Operations
Clearwater		292		335		374		8.6		9.9		8.6
Bighorn		158		255		242		7.5		8.9		5.8
Deep Panuke		190		41		—		—		—		—
Other and emerging		213		334		338		0.3		0.9		0.9

Total Canadian Operations		1,378		1,432		1,359		37.2		30.4		19.4

USA Operations
Eagle Ford		19		—		—		19.8		—		—
Permian		5		—		—		3.5		—		—
DJ Basin		43		39		41		11.6		8.4		3.1
San Juan		8		3		—		3.9		1.4		0.2
Other Upstream Operations
Piceance		402		455		475		5.0		5.1		2.2
Haynesville		311		348		475		—		—		—
Jonah		100		323		411		1.8		4.7		4.1
East Texas		57		136		167		0.5		1.0		0.5
Other and emerging		27		41		53		3.5		2.9		1.5

Total USA Operations		972		1,345		1,622		49.6		23.5		11.6

Total Production Volumes		2,350		2,777		2,981		86.8		53.9		31.0

Total Production Volumes – Growth Assets		600		509		446		61.4		21.5		8.1

The Production Volumes by Play presentation has been updated to align with the Company’s business strategy. The table above reflects the Eagle Ford and Permian acquisitions as well as Montney, Duvernay, DJ Basin and San Juan, which have been segregated for presentation in 2014 as Encana focuses capital on these specific growth assets. Growth assets also includes the Tuscaloosa Marine Shale (“TMS”) reported within Other and emerging results in the USA Operations. Other Upstream Operations includes production volumes from plays that are not part of the Company’s current strategic focus as well as prospective plays that are under appraisal.

The production volumes associated with the lands transferred to PrairieSky were included in Encana’s Clearwater play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.

22 Encana Corporation | Annual Report 2014

2014 versus 2013

In 2014, average natural gas production volumes of 2,350 MMcf/d decreased 427 MMcf/d from 2013 primarily due to divestitures resulting from the Company’s strategic transition to a more balanced commodity portfolio and natural declines, partially offset by production from Deep Panuke. The Canadian Operations volumes were lower in 2014 primarily due to the sale of the Bighorn assets, the sale of the Jean Marie natural gas assets and natural declines, partially offset by higher production volumes from Deep Panuke and a successful drilling program in Montney. The USA Operations volumes were lower in 2014 primarily due to the sale of the Jonah and East Texas properties and natural declines mainly in Piceance and Haynesville.

In 2014, average oil and NGL production volumes of 86.8 Mbbls/d increased 32.9 Mbbls/d from 2013 primarily due to acquisitions and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures. The Canadian Operations volumes were higher in 2014 primarily due to successful drilling programs, mainly in Montney, partially offset by the sale of the Bighorn assets. The Canadian Operations volumes were also impacted by the sale of the Company’s investment in PrairieSky, partially offset by higher royalty volumes in Clearwater associated with the lands transferred to PrairieSky. The USA Operations volumes were higher in 2014 primarily due to the acquisition of Eagle Ford and the Permian assets and successful drilling programs in the DJ Basin and San Juan, partially offset by the sale of the Jonah properties.

2013 versus 2012

In 2013, average natural gas production volumes of 2,777 MMcf/d decreased 204 MMcf/d from 2012 primarily due to the Company’s capital investment focus in oil and liquids rich natural gas plays, a reduced capital investment program and natural declines, partially offset by shut-in production volumes in 2012. The Canadian Operations volumes were higher primarily due to successful drilling programs, production volumes from Deep Panuke and shut-in production volumes in 2012, partially offset by natural declines and the sale of the Jean Marie natural gas assets. The USA Operations volumes were lower primarily due to natural declines, partially offset by shut-in production volumes in 2012.

In 2013, average oil and NGL production volumes of 53.9 Mbbls/d increased 22.9 Mbbls/d from 2012. The Canadian Operations volumes were higher primarily due to the extraction of additional liquids volumes in Bighorn and Montney and successful drilling programs in Montney and Clearwater. The USA Operations volumes were higher primarily due to successful drilling programs in oil and liquids rich natural gas plays and new and renegotiated gathering and processing agreements which resulted in additional NGL volumes primarily in Piceance and Jonah.

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Annual Report 2014 | Encana Corporation 23

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NET CAPITAL INVESTMENT


($ millions)	2014			2013			2012
Canadian Operations	$	1,226		$	1,365		$	1,567
USA Operations		1,285			1,283			1,727
Market Optimization		—			3			7
Corporate & Other		15			61			175

Capital Investment		2,526			2,712			3,476

Acquisitions		3,016			184			379
Divestitures		(4,345	)		(705	)		(4,043	)

Net Acquisitions & (Divestitures)		(1,329	)		(521	)		(3,664	)

Net Capital Investment	$	1,197		$	2,191		$	(188	)

CAPITAL INVESTMENT BY PLAY


($ millions)	2014		2013 ⁽¹⁾		2012 ⁽¹⁾
Canadian Operations
Montney	$	776	$	565	$	416
Duvernay		328		155		224
Other Upstream Operations
Clearwater		48		193		220
Bighorn		22		304		363
Deep Panuke		8		46		55
Other and emerging		44		102		289

Total Canadian Operations	$	1,226	$	1,365	$	1,567

USA Operations
Eagle Ford	$	274	$	—	$	—
Permian		117		—		—
DJ Basin		277		181		133
San Juan		287		166		84
Other Upstream Operations
Piceance		48		266		360
Haynesville		51		220		349
Jonah		25		58		116
East Texas		9		106		172
Other and emerging		197		286		513

Total USA Operations	$	1,285	$	1,283	$	1,727

Capital Investment – Growth Assets	$	2,160	$	1,165	$	1,010

(1)	2013 and 2012 capital reflect the reclassification of capitalized operating costs from Other and emerging to the plays presented.

The Capital Investment by Play presentation has been updated to align with the Company’s business strategy. The table above reflects the Eagle Ford and Permian acquisitions as well as Montney, Duvernay, DJ Basin and San Juan, which have been segregated for presentation in 2014 as Encana focuses capital on these specific growth assets. Growth assets also includes the TMS reported within Other and emerging results in the USA Operations. For the year ended December 31, 2014, capital investment in the TMS was $101 million (2013 – $98 million; 2012 – $153 million). Other Upstream Operations includes capital investment from plays that are not part of the Company’s current strategic focus as well as prospective plays that are under appraisal.

Capital investment associated with the lands transferred to PrairieSky was included in Encana’s Clearwater play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.

24 Encana Corporation | Annual Report 2014

2014

Capital investment during 2014 was $2,526 million compared to $2,712 million in 2013. The Company’s disciplined capital spending focused on investment in high return scalable projects and opportunities where development has demonstrated success, as well as executing drilling programs with joint venture partners. During 2014, capital spending in the Company’s growth assets totaled $2,160 million, representing approximately 86 percent of the Company’s capital investment.

Acquisitions

Acquisitions in 2014 were $21 million in the Canadian Operations and $2,995 million in the USA Operations, which primarily included land and property purchases with oil and liquids rich production potential.

The USA Operations included approximately $2.9 billion, after closing adjustments, related to the acquisition of Eagle Ford. The Eagle Ford acquisition included 45,500 net acres located in the Eagle Ford shale formation in south Texas and provides significant oil reserves to the Company. Further information on the acquisition of Eagle Ford, including unaudited pro forma financial information, can be found in Note 3 to the Consolidated Financial Statements.

Divestitures

Divestitures in 2014 were $1,847 million in the Canadian Operations and $2,264 million in the USA Operations, which primarily included the sale of land and properties to balance the commodity mix in support of the Company’s business strategy.

The Canadian Operations included approximately $1.7 billion, after closing adjustments, for the sale of the Company’s Bighorn assets in west central Alberta which comprised approximately 360,000 net acres of land along with Encana’s working interests in pipelines, facilities and service arrangements.

The USA Operations included approximately $1.6 billion, after closing adjustments, for the sale of the Jonah properties and approximately $495 million for the sale of certain properties in East Texas. The Jonah properties comprised approximately 19,000 net developed acres and 1,200 net wells as well as approximately 102,000 net undeveloped acres in Wyoming. The East Texas properties represented approximately 91,000 net acres located primarily in the Leon and Robertson counties of East Texas.

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 resulted in a significant alteration between capitalized costs and proved reserves in the respective country cost centre. For divestitures that result in a gain or loss and constitute a business, goodwill is allocated to the divestiture. Accordingly, for the year ended December 31, 2014, Encana recognized a gain of approximately $1,014 million, before tax, on the sale of the Company’s Bighorn assets in the Canadian cost centre and allocated goodwill of $257 million. In addition, for the year ended December 31, 2014, Encana recognized a gain of approximately $209 million, before tax, on the sale of the Jonah properties in the U.S. cost centre and allocated goodwill of $68 million.

Other 2014 Capital Transactions

The following transactions involve the acquisition or disposition of common shares and, therefore, are excluded from the Net Capital Investment table.

Acquisition of Athlon

On November 13, 2014, Encana completed the acquisition of all of the issued and outstanding shares of common stock of Athlon for $5.93 billion, or $58.50 per share. As part of the acquisition, Encana assumed Athlon’s $1.15 billion senior notes and repaid and terminated Athlon’s credit facility with indebtedness outstanding of $335 million. The acquisition of Athlon added approximately 137,000 net acres in the Permian Basin in Texas to Encana’s portfolio. The fair value of the assets acquired was $9,405 million including proved and unproved properties totaling $7,462 million and goodwill of $1,724 million. Goodwill arose from the requirement to recognize deferred taxes on the difference between the fair value of the assets acquired and liabilities assumed and the respective carry-over tax basis. Further information on the acquisition of Athlon, including unaudited pro forma financial information, can be found in Note 3 to the Consolidated Financial Statements.

Divestiture of Investment in PrairieSky

On September 26, 2014, Encana completed the secondary offering of 70.2 million common shares of PrairieSky at a price of C$36.50 per common share for aggregate gross proceeds of approximately C$2.6 billion. Following the completion of the secondary offering, Encana no longer holds an interest in PrairieSky. As the sale of the investment in PrairieSky resulted in a significant alteration between capitalized costs and proved reserves in the Canadian cost centre, Encana recognized a gain on divestiture of approximately $2.1 billion, before tax.

During the second quarter of 2014, PrairieSky acquired Encana’s royalty business with assets in Clearwater located predominantly in central and southern Alberta. Subsequently, Encana completed the initial public offering of 59.8 million common shares at a price of C$28.00 per common share for aggregate gross proceeds of approximately C$1.67 billion. Encana retained 70.2 million common shares of PrairieSky, representing a 54 percent ownership interest. For the period in which Encana held an ownership interest, the Company consolidated the financial position and results of operations of PrairieSky and recognized a noncontrolling interest for the third party ownership.

Further information on the PrairieSky transactions can be found in Note 18 to the Consolidated Financial Statements.

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Annual Report 2014 | Encana Corporation 25

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2013

Capital investment during 2013 was $2,712 million and reflected the Company’s disciplined capital spending which focused on investment in Encana’s highest return plays, investments in opportunities where development has demonstrated success and executing drilling programs with joint venture partners. Development continued in Bighorn, Piceance and Haynesville. Investment in the Company’s growth assets was focused on Montney, Duvernay, the DJ Basin and San Juan.

Acquisitions

Acquisitions in 2013 were $28 million in the Canadian Operations and $156 million in the USA Operations, which primarily included land and property purchases with oil and liquids rich production potential.

Divestitures

Divestitures in 2013 were $685 million in the Canadian Operations and $18 million in the USA Operations. The Canadian Operations included the sale of the Company’s Jean Marie natural gas assets in northeast British Columbia and other assets.

2012

Capital investment during 2012 was $3,476 million and focused on completing previously initiated drilling programs, executing drilling programs with joint venture partners and increasing investment in oil and liquids rich natural gas development and exploration opportunities. Development continued in Piceance, Haynesville, Bighorn and Clearwater, as well as in the Company’s growth assets, including Montney, Duvernay, the TMS, the DJ Basin and San Juan. Capital investment in 2012 also continued in Other and emerging.

Acquisitions

Acquisitions in 2012 were $139 million in the Canadian Operations and $240 million in the USA Operations, which primarily included land and property purchases with oil and liquids rich production potential.

Divestitures

Divestitures in 2012 were $3,770 million in the Canadian Operations and $271 million in the USA Operations. The Canadian Operations included C$1.45 billion received from a Mitsubishi Corporation subsidiary, C$1.18 billion received from a PetroChina Company Limited subsidiary, C$100 million received from a Toyota Tsusho Corporation subsidiary and approximately C$920 million received from the sale of two natural gas processing plants. The USA Operations received the remaining proceeds of $114 million from the divestiture of the North Texas natural gas assets, of which the majority of the proceeds were received in December 2011.

26 Encana Corporation | Annual Report 2014

RESULTS OF OPERATIONS

CANADIAN OPERATIONS

OPERATING CASH FLOW


	Natural Gas							Oil & NGLs							Total ⁽¹⁾
($ millions)	2014			2013		2012		2014		2013		2012			2014			2013		2012
Revenues, Net of Royalties, excluding Hedging	$	2,468		$	1,771	$	1,263	$	872	$	722	$	504		$	3,366		$	2,548	$	1,802
Realized Financial Hedging Gain (Loss)		(74	)		271		962		18		5		(4	)		(56	)		276		958

Revenues, Net of Royalties		2,394			2,042		2,225		890		727		500			3,310			2,824		2,760
Expenses
Production and mineral taxes		5			4		1		10		11		8			15			15		9
Transportation and processing		773			724		549		62		32		6			835			756		555
Operating		279			322		327		28		39		14			314			372		352

Operating Cash Flow	$	1,337		$	992	$	1,348	$	790	$	645	$	472		$	2,146		$	1,681	$	1,844

PRODUCTION VOLUMES


	Natural Gas						Oil & NGLs						Total
	(MMcf/d)						(Mbbls/d)						(MBOE/d)
	2014		2013		2012		2014		2013		2012		2014		2013		2012
Production Volumes - After Royalties		1,378		1,432		1,359		37.2		30.4		19.4		266.9		269.0		246.0

OPERATING NETBACK ⁽²⁾


	Natural Gas							Oil & NGLs						Total
	($/Mcf)							($/bbl)						($/BOE)
	2014			2013		2012		2014		2013		2012		2014			2013		2012
Revenues, Net of Royalties, excluding Hedging	$	4.89		$	3.35	$	2.58	$	64.16	$	65.06	$	70.84	$	34.21		$	25.13	$	19.95
Realized Financial Hedging Gain (Loss)		(0.15	)		0.51		1.97		1.36		0.46		—		(0.57	)		2.78		10.81

Revenues, Net of Royalties		4.74			3.86		4.55		65.52		65.52		70.84		33.64			27.91		30.76
Expenses
Production and mineral taxes		0.01			0.01		—		0.71		0.96		1.13		0.15			0.15		0.10
Transportation and processing		1.53			1.37		1.12		4.52		2.89		0.75		8.55			7.62		6.26
Operating		0.55			0.61		0.67		2.09		3.56		2.09		3.14			3.65		3.85

Operating Netback	$	2.65		$	1.87	$	2.76	$	58.20	$	58.11	$	66.87	$	21.80		$	16.49	$	20.55

(1)	Also includes other revenues and expenses, such as third party processing, with no associated volumes.

(2)	A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A.

Annual Report 2014 | Encana Corporation 27

LOGO

2014 versus 2013

Operating Cash Flow of $2,146 million increased $465 million primarily due to the following significant items:

•

Higher natural gas prices reflected higher benchmark prices. Realized natural gas prices for production from Deep Panuke were $8.34 per Mcf which increased the average realized natural gas price $0.54 per Mcf. Higher realized natural gas prices for production, including Deep Panuke, increased revenues $780 million. Lower liquids prices decreased revenues $13 million.

•

Average natural gas production volumes of 1,378 MMcf/d were lower by 54 MMcf/d, which decreased revenues $83 million. Average oil and NGL production volumes of 37.2 Mbbls/d were higher by 6.8 Mbbls/d, which increased revenues $163 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

•

Realized financial hedging losses were $56 million compared to gains of $276 million in 2013.

•

Transportation and processing expense increased $79 million primarily due to costs related to Deep Panuke production and higher liquids volumes processed, partially offset by the lower U.S./Canadian dollar exchange rate and the sale of the Bighorn assets. The Deep Panuke offshore natural gas facility commenced commercial operations in December 2013.

•

Operating expense decreased $58 million primarily due to lower salaries and benefits related to workforce reductions as a result of the 2013 restructuring, the lower U.S./Canadian dollar exchange rate, the sale of the Bighorn assets, the sale of the Jean Marie natural gas assets in the second quarter of 2013 and lower long-term compensation costs due to the decrease in the Encana share price.

2013 versus 2012

Operating Cash Flow of $1,681 million decreased $163 million primarily due to the following significant items:

•

Higher natural gas prices reflected higher benchmark prices, which increased revenues by $405 million. Lower liquids prices decreased revenues by $63 million.

•

Average natural gas production volumes of 1,432 MMcf/d were higher by 73 MMcf/d, which increased revenues by $103 million. Average oil and NGL production volumes of 30.4 Mbbls/d were higher by 11.0 Mbbls/d. This increased revenues by $281 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

•

Realized financial hedging gains were $276 million compared to $958 million in 2012.

•

Transportation and processing expense increased $201 million primarily due to costs related to higher production volumes processed through third party facilities in Bighorn and Montney, costs related to the Deep Panuke offshore natural gas facility and higher firm processing costs.

OTHER EXPENSES


($ millions, except as indicated)	2014		2013		2012
Depreciation, depletion & amortization	$	625	$	601	$	748
Depletion rate ($/BOE)		6.40		6.06		8.44
Impairments		—		—		1,822

In 2014, DD&A increased from 2013 primarily due to a higher depletion rate of $6.40 per BOE in 2014 compared to $6.06 per BOE in 2013, partially offset by the lower U.S./Canadian dollar exchange rate. The depletion rate was impacted by the sale of the Bighorn assets, the sale of the Company’s investment in PrairieSky, a decline in proved reserves due to Encana’s change in development plans as the Company strategically transitions to a more balanced commodity portfolio and the lower U.S./Canadian dollar exchange rate.

In 2013, DD&A decreased from 2012 due to a lower depletion rate of $6.06 per BOE in 2013 compared to $8.44 per BOE in 2012, partially offset by higher production volumes in 2013. The lower depletion rate primarily resulted from ceiling test impairments recognized in 2012 and deductions from the full cost pool for amounts received from divestitures during 2012 and 2013.

In 2012, the Canadian Operations recognized non-cash ceiling test impairments before tax of $1,822 million. The impairments primarily resulted from the decline in the 12-month average trailing natural gas prices, which reduced the Canadian Operations proved reserves volumes and values as calculated under SEC requirements.

28 Encana Corporation | Annual Report 2014

USA OPERATIONS

OPERATING CASH FLOW


	Natural Gas							Oil & NGLs						Total ⁽¹⁾
($ millions)	2014			2013		2012		2014		2013		2012		2014			2013		2012
Revenues, Net of Royalties, excluding Hedging	$	1,640		$	1,872	$	1,798	$	1,258	$	602	$	348	$	2,927		$	2,499	$	2,170
Realized Financial Hedging Gain (Loss)		(85	)		260		1,195		60		4		—		(25	)		264		1,195

Revenues, Net of Royalties		1,555			2,132		2,993		1,318		606		348		2,902			2,763		3,365
Expenses
Production and mineral taxes		44			77		68		74		42		28		118			119		96
Transportation and processing		651			722		652		7		—		—		658			722		652
Operating		235			339		347		115		59		25		354			411		377

Operating Cash Flow	$	625		$	994	$	1,926	$	1,122	$	505	$	295	$	1,772		$	1,511	$	2,240

PRODUCTION VOLUMES


	Natural Gas						Oil & NGLs						Total
	(MMcf/d)						(Mbbls/d)						(MBOE/d)
	2014		2013		2012		2014		2013		2012		2014		2013		2012
Production Volumes - After Royalties		972		1,345		1,622		49.6		23.5		11.6		211.6		247.7		281.9

OPERATING NETBACK ⁽²⁾


	Natural Gas							Oil & NGLs						Total
	($/Mcf)							($/bbl)						($/BOE)
	2014			2013		2012		2014		2013		2012		2014			2013		2012
Revenues, Net of Royalties, excluding Hedging	$	4.62		$	3.81	$	3.03	$	69.54	$	70.18	$	82.33	$	37.53		$	27.37	$	20.79
Realized Financial Hedging Gain (Loss)		(0.24	)		0.53		2.01		3.29		0.44		—		(0.33	)		2.93		11.58

Revenues, Net of Royalties		4.38			4.34		5.04		72.83		70.62		82.33		37.20			30.30		32.37
Expenses
Production and mineral taxes		0.12			0.16		0.11		4.10		4.79		6.63		1.53			1.31		0.93
Transportation and processing		1.83			1.47		1.10		0.39		—		0.06		8.52			7.98		6.32
Operating		0.66			0.69		0.59		6.36		7.02		5.88		4.53			4.42		3.61

Operating Netback	$	1.77		$	2.02	$	3.24	$	61.98	$	58.81	$	69.76	$	22.62		$	16.59	$	21.51

(1)	Also includes other revenues and expenses, such as third party processing, with no associated volumes.

(2)	A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A.

2014 versus 2013

Operating Cash Flow of $1,772 million increased $261 million primarily due to the following significant items:

•

Higher natural gas prices reflected higher benchmark prices, which increased revenues $287 million. Lower liquids prices decreased revenues $10 million.

•

Average natural gas production volumes of 972 MMcf/d were lower by 373 MMcf/d, which decreased revenues $519 million. Average oil and NGL production volumes of 49.6 Mbbls/d were higher by 26.1 Mbbls/d, which increased revenues $666 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

•

Realized financial hedging losses were $25 million compared to gains of $264 million in 2013.

•

Transportation and processing expense decreased $64 million primarily due to the sale of the Jonah and East Texas properties.

•

Operating expense decreased $57 million primarily due to lower salaries and benefits related to workforce reductions as a result of the 2013 restructuring, the sale of the Jonah properties and lower long-term compensation costs due to the decrease in the Encana share price, partially offset by the acquisition of Eagle Ford and the Permian assets.

LOGO

Annual Report 2014 | Encana Corporation 29

LOGO

2013 versus 2012

Operating Cash Flow of $1,511 million decreased $729 million primarily due to the following significant items:

•

Higher natural gas prices reflected higher benchmark prices, which increased revenues by $385 million. Lower liquids prices decreased revenues by $105 million.

•

Average natural gas production volumes of 1,345 MMcf/d were lower by 277 MMcf/d. This decreased revenues by $311 million. Average oil and NGL production volumes of 23.5 Mbbls/d were higher by 11.9 Mbbls/d. This increased revenues by $359 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

•

Realized financial hedging gains were $264 million compared to $1,195 million in 2012.

•

Transportation and processing expense increased $70 million primarily due to costs related to new and renegotiated gathering and processing agreements.

•

Operating expense increased $34 million primarily due to an increased focus on emerging oil and liquids rich natural gas plays.

OTHER EXPENSES


($ millions, except as indicated)	2014		2013		2012
Depreciation, depletion & amortization	$	992	$	818	$	1,102
Depletion rate ($/BOE)		12.85		9.05		10.67
Impairments		—		—		2,842

In 2014, DD&A increased from 2013 due to a higher depletion rate of $12.85 per BOE in 2014 compared to $9.05 per BOE in 2013, partially offset by lower production volumes. The higher depletion rate in 2014 resulted primarily from the acquisition of Eagle Ford and the Permian assets, the sale of the Jonah properties and a decline in proved reserves due to Encana’s change in development plans as the Company strategically transitions to a more balanced commodity portfolio.

In 2013, DD&A decreased from 2012 due to a lower depletion rate of $9.05 per BOE in 2013 compared to $10.67 per BOE in 2012 and lower production volumes in 2013. The lower depletion rate primarily resulted from ceiling test impairments recognized during 2012.

In 2012, the USA Operations recognized non-cash ceiling test impairments before tax of $2,842 million. The impairments primarily resulted from the decline in the 12-month average trailing natural gas prices, which reduced the USA Operations proved reserves volumes and values as calculated under SEC requirements.

MARKET OPTIMIZATION


($ millions)	2014		2013		2012
Revenues	$	1,248	$	512	$	419
Expenses
Operating		39		38		48
Purchased product		1,191		441		349
Depreciation, depletion and amortization		4		12		12

	$	14	$	21	$	10

Market Optimization revenues and purchased product expense relate to activities that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. Revenues and purchased product expense increased in 2014 compared to 2013 primarily due to generally higher commodity prices, and higher third party purchases and sales of product resulting from transitional services related to the Company’s divestiture activity. Revenues and purchased product expense increased in 2013 compared to 2012 primarily due to higher commodity prices, partially offset by lower volumes required for optimization.

30 Encana Corporation | Annual Report 2014

CORPORATE AND OTHER


($ millions)	2014		2013			2012
Revenues	$	559	$	(241	)	$	(1,384	)
Expenses
Transportation and processing		12		(2	)		24
Operating		28		38			17
Depreciation, depletion and amortization		124		134			94
Impairments		—		21			31

	$	395	$	(432	)	$	(1,550	)

Revenues mainly include unrealized hedging gains or losses recorded on derivative financial contracts which result from the volatility in forward curves of commodity prices and changes in the balance of unsettled contracts between periods. Transportation and processing expense reflects unrealized financial hedging gains or losses related to the Company’s power financial derivative contracts. DD&A includes amortization of corporate assets, such as computer equipment, office buildings, furniture and leasehold improvements. Impairments relates to certain corporate assets.

Corporate and Other results include revenues and operating expenses related to the sublease of office space in The Bow office building. Further information on The Bow office sublease can be found in the Contractual Obligations and Contingencies section of this MD&A as well as Note 14 to the Consolidated Financial Statements.

OTHER OPERATING RESULTS

EXPENSES


($ millions)	2014			2013			2012
Accretion of asset retirement obligation	$	52		$	53		$	53
Administrative		327			439			392
Interest		654			563			522
Foreign exchange (gain) loss, net		403			325			(107	)
(Gain) loss on divestitures		(3,426	)		(7	)		—
Other		71			1			1

	$	(1,919	)	$	1,374		$	861

Administrative expense in 2014 decreased from 2013 primarily due to lower restructuring costs, lower long-term compensation costs and the lower U.S./Canadian dollar exchange rate. The decrease also reflects the cost savings attributable to workforce reductions associated with the 2013 restructuring. Restructuring costs incurred in 2014 were approximately $36 million compared to $88 million in 2013. Administrative expense in 2013 increased from 2012 primarily due to restructuring charges resulting from workforce reductions to align the organizational structure in support of the strategy announced in November 2013, partially offset by higher legal costs in 2012.

Interest expense in 2014 increased from 2013 primarily due to a one-time outlay of approximately $125 million associated with the early redemption of senior notes assumed in conjunction with the acquisition of Athlon and higher interest related to the Deep Panuke Production Field Centre (“PFC”), partially offset by lower interest on debt resulting from the long-term debt repayment and redemption in the first six months of 2014. Interest expense in 2013 increased from 2012 primarily due to interest related to The Bow office building. Further information on the PFC capital lease and The Bow office building can be found in the Contractual Obligations and Contingencies section of this MD&A as well as Note 14 to the Consolidated Financial Statements.

Foreign exchange gains and losses result from the impact of the fluctuations in the Canadian to U.S. dollar exchange rate. Foreign exchange gains and losses primarily arise from the revaluation and settlement of U.S. dollar long-term debt issued from Canada and the revaluation and settlement of other monetary assets and liabilities.

The gain on divestitures in 2014 primarily includes the before tax impact of the sale of Encana’s investment in PrairieSky, the Bighorn assets and the Jonah properties as discussed in the Net Capital Investment section of this MD&A.

Other in 2014 includes transaction costs associated with the acquisitions of Athlon and Eagle Ford as well as reclamation charges relating to non-producing assets.

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INCOME TAX


($ millions)	2014		2013			2012
Current Income Tax (Recovery)	$	243	$	(191	)	$	(200	)
Deferred Income Tax (Recovery)		960		(57	)		(1,837	)

Income Tax Expense (Recovery)	$	1,203	$	(248	)	$	(2,037	)

Current income tax expense in 2014 was $243 million compared to a recovery of $191 million in 2013. The current income tax expense in 2014 was primarily due to current taxes incurred on divestitures. The current income tax recovery in 2013 was primarily due to amounts in respect of prior periods. The current income tax recovery of $200 million in 2012 was primarily due to the carry back of tax losses to prior years.

Total income tax expense in 2014 was higher due to higher net earnings before tax primarily resulting from gains on divestitures and unrealized hedging gains, and amounts in respect of prior periods recognized in 2013. Total income tax was a recovery of $248 million in 2013 and decreased $1,789 million compared to 2012 primarily due to higher net earnings before tax mainly resulting from the non-cash ceiling test impairments included in the 2012 results. The Net Earnings variances are further discussed in the Financial Results section of this MD&A.

Encana’s annual effective tax rate is impacted by earnings, statutory rate and other foreign differences, the effect of legislative changes, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.

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

LIQUIDITY AND CAPITAL RESOURCES


($ millions)	2014			2013			2012
Net Cash From (Used In)
Operating activities	$	2,667		$	2,289		$	3,107
Investing activities		(4,729	)		(1,895	)		361
Financing activities		(39	)		(909	)		(1,111	)
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency		(127	)		(98	)		22

Increase (Decrease) in Cash and Cash Equivalents	$	(2,228	)	$	(613	)	$	2,379

Cash and Cash Equivalents, End of Year	$	338		$	2,566		$	3,179

OPERATING ACTIVITIES

Net cash from operating activities in 2014 of $2,667 million increased $378 million from 2013. Net cash from operating activities in 2013 of $2,289 million decreased $818 million from 2012. These changes are primarily a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In 2014, the net change in non-cash working capital was a deficit of $9 million compared to $179 million in 2013 and $323 million in 2012.

The Company had a working capital surplus of $455 million at December 31, 2014 compared to $1,338 million at December 31, 2013. The decrease in working capital is primarily due to a decrease in cash and cash equivalents, an increase in accounts payable and accrued liabilities, an increase in deferred income tax liabilities and a decrease in deferred income tax assets, partially offset by a decrease in the current portion of long-term debt, an increase in risk management assets and an increase in accounts receivable and accrued revenues. At December 31, 2014, working capital included cash and cash equivalents of $338 million compared to $2,566 million at December 31, 2013. Encana expects that it will continue to meet the payment terms of its suppliers.

INVESTING ACTIVITIES

Net cash used in investing activities in 2014 was $4,729 million compared to $1,895 million in 2013. The increase was primarily due to the acquisitions of Athlon and Eagle Ford, partially offset by proceeds from the Bighorn, Jonah and East Texas divestitures and proceeds from the sale of the Company’s investment in PrairieSky. Net cash used in investing activities in 2013 was $1,895 million compared to net cash from investing activities of $361 million in 2012. The net cash used in investing activities primarily resulted from lower divestiture proceeds, partially offset by lower capital expenditures. Investing activities in 2013 included proceeds from the sale of the Company’s 30 percent interest in the proposed Kitimat liquefied natural gas export terminal which closed in February 2013. Further information on capital expenditures, acquisitions and divestitures can be found in the Net Capital Investment section of this MD&A.

Net cash used in investing activities in 2014 also included cash in reserve added to escrow of $63 million compared to $44 million and $415 million released from escrow in 2013 and 2012, respectively. Cash in reserve includes monies which are not available for general operating use, are segregated or held in escrow and include amounts received from counterparties related to jointly developed assets.

32 Encana Corporation | Annual Report 2014

FINANCING ACTIVITIES

Net cash used in financing activities in 2014 was $39 million compared to $909 million in 2013. The decrease primarily resulted from the sale of a noncontrolling interest in PrairieSky for proceeds of $1,462 million and the issuance of revolving long-term debt of $1,277 million, partially offset by the repayment of long-term debt totaling $2,487 million as discussed below. Net cash used in financing activities in 2013 was $909 million compared to $1,111 million in 2012. The decrease in cash used primarily resulted from lower cash dividend payments in 2013.

LONG-TERM DEBT

Encana’s long-term debt, excluding the current portion, totaled $7,340 million at December 31, 2014 and $6,124 million at December 31, 2013. The current portion of long-term debt outstanding was nil at December 31, 2014 compared to $1,000 million at December 31, 2013.

At December 31, 2014, Encana had an outstanding balance of $1,277 million under the Company’s existing revolving credit facility. The outstanding balance reflects principal obligations related to LIBOR loans maturing at various dates with a weighted average interest rate of 1.62 percent. These amounts are fully supported and Management expects they will continue to be supported by revolving credit facilities that have no repayment requirements within the next year. There were no outstanding balances at December 31, 2013. Additional detail on Encana’s credit facilities can be found below and in Note 13 to the Consolidated Financial Statements.

On January 29, 2015, Encana implemented a U.S. Commercial Paper program (“U.S. CP Program”) with $2.0 billion of capacity, which reduces the Company’s borrowing costs. As of February 23, 2015, Encana had repaid the outstanding balance of $1,277 million which was drawn on the Company’s revolving credit facility using $1.1 billion of proceeds from the U.S. CP Program and cash on hand.

Encana has the flexibility to refinance maturing long-term debt or repay debt maturities from existing sources of liquidity. Encana’s primary sources of liquidity include cash and cash equivalents, revolving bank credit facilities, working capital, operating cash flow and proceeds from asset divestitures.

REDEMPTION OF ATHLON DEBT ASSUMED

On November 13, 2014, Encana completed the acquisition of all issued and outstanding shares of common stock of Athlon and assumed Athlon’s $500 million 7.375 percent senior notes due April 15, 2021 and $650 million 6.00 percent senior notes due May 1, 2022. In conjunction with the acquisition, Encana repaid and terminated Athlon’s credit facility with indebtedness outstanding of $335 million. Encana funded the acquisition with cash on hand.

On December 16, 2014, Encana completed the redemption of all of Athlon’s senior notes. The Company recognized a one-time outlay of approximately $125 million as a result of the redemption, but expects to save approximately $515 million in future interest expense associated with these notes. Upon acquisition, the Company recorded an increase in the fair value of the debt acquired from Athlon of approximately $12 million, which was expensed upon redemption of the senior notes and is included in Other expenses in the Company’s Consolidated Statement of Earnings. Encana used proceeds from the Company’s revolving credit facility of $1,277 million to redeem the senior notes.

REDEMPTION OF 5.80 PERCENT NOTES

On February 28, 2014, Encana announced a cash tender offer and consent solicitation for any and all of the Company’s outstanding $1,000 million 5.80 percent notes with a maturity date of May 1, 2014. The Company paid $1,004.59 for each $1,000 principal amount of the notes plus accrued and unpaid interest up to, but not including, the settlement date and a consent payment equal to $2.50 per $1,000 principal amount of the notes.

On March 28, 2014, the tender offer and consent solicitation expired and, on March 31, 2014, Encana paid the consenting note holders an aggregate of approximately $792 million in cash reflecting a $768 million principal debt repayment, $2 million for the consent payment and $22 million of accrued and unpaid interest.

On April 28, 2014, pursuant to the Notice of Redemption issued on March 28, 2014, the Company redeemed the remaining principal amount of the 5.80 percent notes not tendered in the tender offer. Encana paid approximately $239 million in cash reflecting a $232 million principal debt repayment and $7 million of accrued and unpaid interest.

CREDIT FACILITIES AND SHELF PROSPECTUS

Encana maintains two revolving bank credit facilities which remain committed through June 2018. At December 31, 2014, Encana had available unused committed revolving bank credit facilities of $2.7 billion as follows:

•

A committed revolving bank credit facility for C$3.5 billion ($3.0 billion) for Encana, of which $1.7 billion remained unused.

•

A committed revolving bank credit facility for a U.S. subsidiary for $1.0 billion, all of which remained unused.

On June 27, 2014, Encana filed a short form base shelf prospectus, whereby the Company may issue from time to time up to $6.0 billion, or the equivalent in foreign currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants and units in Canada and/or the U.S. At December 31, 2014, the shelf prospectus remained accessible, the availability of which is dependent upon market conditions. The shelf prospectus expires in July 2016. This shelf prospectus replaced a $4.0 billion debt shelf prospectus which expired in June 2014.

Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under its credit facility agreements. Management monitors Debt to Adjusted Capitalization as a proxy for Encana’s financial covenant under its credit facility agreements which require 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. Debt to Adjusted Capitalization was 30 percent at December 31, 2014 and 36 percent at December 31, 2013.

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OUTSTANDING SHARE DATA


(millions)	February 24, 2015		December 31, 2014
Common Shares Outstanding		741.2		741.2
Stock Options with TSARs attached:
Outstanding		19.3		21.3
Exercisable		11.4		10.0

Eligible employees have been granted stock options to purchase common shares in accordance with Encana’s Employee Stock Option Plan. A Tandem Stock Appreciation Right (“TSAR”) gives 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 exercise over the original grant price. The exercise of a TSAR for a cash payment does not result in the issuance of any Encana common shares and, therefore, has no dilutive effect. Historically, most holders of these options have elected to exercise their stock options as a TSAR in exchange for a cash payment.

Restricted Share Units (“RSUs”) have been granted to eligible employees to receive an Encana common share, or the cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The value of one RSU is notionally equivalent to one Encana common share. As at December 31, 2014, there were approximately 9.0 million outstanding RSUs which vest three years from the date granted. The Company intends to settle vested RSUs in cash on the vesting date. A settlement in cash does not result in the issuance of any Encana common shares and, therefore, has no dilutive effect.

During 2014, Encana issued 240,839 common shares under the Company’s dividend reinvestment plan (“DRIP”) compared with 5.4 million common shares in 2013. The number of common shares issued under the DRIP decreased in 2014 as a result of Encana’s February 2014 announcement that any future dividends in conjunction with the DRIP will be issued from its treasury without a discount to the average market price unless otherwise announced by the Company via news release. Prior to the February 2014 announcement, dividends issued under the DRIP were subject to a two percent discount.

DIVIDENDS

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


($ millions, except as indicated)	2014		2013
Dividend Payments	$	207	$	494
Dividend Payments ($/share)	$	0.28	$	0.67

The dividends paid in 2014 included $5 million in common shares issued in lieu of cash dividends under the Company’s DRIP as disclosed above compared to $93 million for 2013.

On February 25, 2015, the Board declared a dividend of $0.07 per share payable on March 31, 2015 to common shareholders of record as of March 13, 2015.

On February 25, 2015, Encana announced that its Board has determined that effective with the dividend payable on March 31, 2015, all common shares distributed to participating shareholders pursuant to the Company’s DRIP will be issued from Encana’s treasury at a two percent discount to the average market price of the common shares. Any future dividends of common shares distributed to DRIP participants will be issued with the discount unless otherwise announced by Encana by way of news release.

CAPITAL STRUCTURE

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 managing and adjusting its capital structure according to market conditions to maintain flexibility while achieving the Company’s objectives.

To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, issue new shares, issue new debt or repay existing debt. In managing its capital structure, the Company monitors the following non-GAAP financial metrics as indicators of its overall financial strength, which are defined in the Non-GAAP Measures section of this MD&A.


	2014			2013			2012
Debt to Debt Adjusted Cash Flow		2.1x			2.4x			2.0x
Debt to Adjusted Capitalization		30	%		36	%		37	%

34 Encana Corporation | Annual Report 2014

CONTRACTUAL OBLIGATIONS AND CONTINGENCIES

CONTRACTUAL OBLIGATIONS

The following table outlines the Company’s commitments at December 31, 2014:


	Expected Future Payments
($ millions, undiscounted)	2015			2016			2017			2018			2019			Thereafter			Total
Long-Term Debt ⁽¹⁾	$	—		$	—		$	700		$	1,924		$	500		$	4,200		$	7,324
Asset Retirement Obligation		44			44			180			23			23			3,313			3,627
Other Long-Term Obligations		80			81			82			82			83			1,652			2,060
Capital Leases		98			98			99			99			99			232			725

Obligations ⁽²⁾		222			223			1,061			2,128			705			9,397			13,736

Transportation and Processing		878			825			815			800			673			3,204			7,195
Drilling and Field Services		312			138			93			47			16			17			623
Operating Leases		43			36			28			26			10			24			167

Commitments		1,233			999			936			873			699			3,245			7,985

Total Contractual Obligations	$	1,455		$	1,222		$	1,997		$	3,001		$	1,404		$	12,642		$	21,721

Sublease Recoveries	$	(39	)	$	(40	)	$	(40	)	$	(40	)	$	(41	)	$	(812	)	$	(1,012	)

(1)	Principal component only. See Note 13 to the Consolidated Financial Statements.

(2)	The Company has recorded $10,255 million in liabilities related to these obligations.

Contractual obligations arising from long-term debt, asset retirement obligations, The Bow office building and capital leases are recognized on the Company’s balance sheet. Further information can be found in the note disclosures to the Consolidated Financial Statements.

Other Long-Term Obligations relates to the 25-year lease agreement with a third party developer for The Bow office building. Encana has recognized the accumulated construction costs for The Bow office building as an asset with a related liability. In 2012, Encana commenced payments to the third party developer. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized. Encana has subleased part of The Bow office space to a subsidiary of Cenovus Energy Inc. (“Cenovus”). Sublease Recoveries in the table above include the amounts expected to be recovered from Cenovus. Encana’s undiscounted payments for The Bow are $2,060 million, of which $1,012 million is expected to be recovered from Cenovus.

Capital Leases primarily includes the obligation related to the Deep Panuke PFC, which commenced commercial operations in December 2013 following issuance of the Production Acceptance Notice. Encana’s undiscounted future lease payments for the Deep Panuke PFC total $625 million ($462 million discounted).

In addition to the Commitments disclosed above, Encana has significant development commitments with joint venture partners, a portion of which may be satisfied by the Drilling and Field Services commitments included in the table above. Encana also has obligations related to its risk management program and to fund its defined benefit pension and other post-employment benefit plans. Further information can be found in Note 23 to the Consolidated Financial Statements regarding the Company’s risk management program. The Company expects to fund its 2015 commitments and obligations from Cash Flow and cash and cash equivalents.

CONTINGENCIES

Encana is involved in various legal claims and actions arising in the course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encana’s financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of a material adverse impact on the Company’s consolidated net earnings or loss in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable and the amount can be reasonably estimated. The Company believes it has made adequate provision for such legal claims.

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RISK MANAGEMENT

Encana’s business, prospects, financial condition, results of operation and cash flows, and in some cases its reputation, are impacted by risks that can be categorized as follows:

•

financial risks;

•

operational risks; and

•

environmental, regulatory, reputational and safety risks.

Encana aims to strengthen its position as a leading North American energy producer and grow shareholder value through a disciplined focus on generating profitable growth. Encana continues to focus on developing a balanced portfolio of low-risk and low-cost long-life plays, which allows the Company to respond well to market uncertainties. Management adjusts financial and operational risk strategies to proactively respond to changing economic conditions and to mitigate or reduce risk.

Issues that can affect Encana’s reputation are generally strategic or emerging issues that can be identified early and then appropriately managed, but can also include unforeseen issues that must be managed on a more urgent basis. Encana takes a proactive approach to the identification and management of issues that affect the Company’s reputation and has established appropriate policies, procedures, guidelines and responsibilities for identifying and managing these issues.

FINANCIAL RISKS

Encana defines financial risks as the risk of loss or lost opportunity resulting from financial management and market conditions that could have an impact on Encana’s business.

Financial risks include, but are not limited to:

•

market pricing of natural gas and liquids;

•

credit and liquidity;

•

foreign exchange rates; and

•

interest rates.

Encana partially mitigates its exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative financial instruments is governed under formal policies and is subject to limits established by the Board. All derivative financial agreements are with major global financial institutions or with corporate counterparties having investment grade credit ratings. Encana has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use to the mitigation of financial risk to achieve investment returns and growth objectives, while maintaining prescribed financial metrics.

To partially mitigate commodity price risk, the Company may enter into transactions that fix, set a floor or set a floor and cap on prices. To help protect against regional price differentials, Encana executes transactions to manage the price differentials between its production areas and various sales points. Further information, including the details of Encana’s financial instruments as at December 31, 2014, is disclosed in Note 23 to the Consolidated Financial Statements.

Counterparty credit risks are regularly and proactively managed. A substantial portion of Encana’s credit exposure is with customers in the oil and gas industry or financial institutions. This credit exposure is mitigated through the use of Board-approved credit policies governing the Company’s credit portfolio, including credit practices that limit transactions and grant payment terms according to industry standards and counterparties’ credit quality.

The Company manages liquidity risk using cash and debt management programs. The Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities and debt and equity capital markets. Encana closely monitors the Company’s ability to access cost-effective credit and ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. The Company minimizes its liquidity risk by managing its capital structure which may include adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, issuing new debt or repaying existing debt.

As a means of mitigating the exposure to fluctuations in the U.S./Canadian dollar exchange rate, Encana may enter into foreign exchange contracts. Realized gains or losses on these contracts are recognized on settlement. By maintaining U.S. and Canadian operations, Encana has a natural hedge to some foreign exchange exposure.

Encana also maintains a mix of both U.S. dollar and Canadian dollar debt. This helps to offset the exposure to the fluctuations in the U.S./Canadian dollar exchange rate. In addition to direct issuance of U.S. dollar denominated debt, the Company may enter into cross currency swaps on a portion of its debt as a means of managing the U.S./Canadian dollar debt mix.

The Company may partially mitigate its exposure to interest rate changes by holding a mix of both fixed and floating rate debt. Encana may enter into interest rate swap transactions from time to time as an additional means of managing the fixed/floating rate debt portfolio mix.

36 Encana Corporation | Annual Report 2014

OPERATIONAL RISKS

Operational risks are defined as the risk of loss or lost opportunity resulting from the following:

•

operating activities;

•

capital activities, including the ability to complete projects; and

•

reserves and resources replacement.

The Company’s ability to operate, generate cash flows, complete projects, and value reserves and resources is subject to financial risks, including commodity prices mentioned above, continued market demand for its products and other risk factors outside of its control. These factors include: general business and market conditions; economic recessions and financial market turmoil; the overall state of the capital markets, including investor appetite for investments in the oil and gas industry generally and the Company’s securities in particular; the ability to secure and maintain cost-effective financing for its commitments; legislative, environmental and regulatory matters; unexpected cost increases; royalties; taxes; volatility in natural gas and liquids prices; partner funding for their share of joint venture and partnership commitments; the availability of drilling and other equipment; the ability to access lands; the ability to access water for hydraulic fracturing operations; weather; the availability of processing capacity; the availability and proximity of take-away capacity; technology failures; cyber attacks; accidents; the availability of skilled labour; and reservoir quality. If Encana fails to acquire or find additional natural gas and liquids reserves and resources, its reserves, resources and production will decline materially from their current levels and, therefore, its cash flows are highly dependent upon successfully exploiting current reserves and resources and acquiring, discovering or developing additional reserves and resources. To mitigate these risks, as part of the capital approval process, the Company’s projects are evaluated on a fully risked basis, including geological risk, engineering risk and reliance on third party service providers.

In addition, Encana undertakes a thorough review of previous capital programs to identify key learnings, which often include operational issues that positively and negatively impact project results. Mitigation plans are developed for the operational issues that had a negative impact on results. These mitigation plans are then incorporated into the current year plan for the project. On an annual basis, these results are analyzed for Encana’s capital program with the results and identified learnings shared across the Company.

A peer review process is used to ensure that capital projects are appropriately risked and that knowledge is shared across the Company. Peer reviews are undertaken primarily for exploration projects and early stage plays, although they may occur for any type of project.

When making operating and investing decisions, Encana’s highly disciplined, dynamic and centrally controlled capital allocation program ensures investment dollars are directed in a manner that is consistent with the Company’s strategy. Encana also mitigates operational risks through a number of other policies, systems and processes as well as by maintaining a comprehensive insurance program.

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ENVIRONMENTAL, REGULATORY, REPUTATIONAL AND SAFETY RISKS

The Company is committed to safety in its operations and has high regard for the environment and stakeholders, including the public and regulators. The Company’s business is subject to all of the operating risks normally associated with the exploration for, development of and production of natural gas, oil and NGLs and the operation of midstream facilities. When assessing the materiality of environmental risk factors, Encana takes into account a number of qualitative and quantitative factors, including, but not limited to, the financial, operational, reputational and regulatory aspects of each identified risk factor. These risks are managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, Encana maintains a system that identifies, assesses and controls safety, security and environmental risk and requires regular reporting to the Executive Leadership Team and the Board. The Corporate Responsibility, Environment, Health and Safety Committee of Encana’s Board provides recommended environmental policies for approval by Encana’s Board and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and audits, are designed to provide assurance that environmental and regulatory standards are met. Emergency response plans are in place to provide guidance during times of crisis. Contingency plans are in place for a timely response to environmental events and remediation/reclamation strategies are utilized to restore the environment.

Encana’s operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion, including hydraulic fracturing and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Changes in government regulation could impact the Company’s existing and planned projects as well as impose a cost of compliance.

One of the processes Encana monitors relates to hydraulic fracturing. Hydraulic fracturing is used throughout the oil and gas industry where fracturing fluids are utilized to develop the reservoir. This process has been used in the oil and gas industry for approximately 60 years. Encana uses multiple techniques to fully understand the effect of each hydraulic fracturing operation it conducts. In all Encana operations, rigorous water management and protection is an essential part of this process.

Hydraulic fracturing processes are strictly regulated by various state and provincial government agencies. Encana meets or exceeds the requirements set out by the regulators. The U.S. and Canadian federal governments and certain U.S. state and Canadian provincial governments are currently reviewing certain aspects of the scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. At present, most of these governments are primarily engaged in the collection, review and assessment of technical information regarding the hydraulic fracturing process and have not provided specific details with respect to any significant actual, proposed or contemplated changes to hydraulic fracturing regulations.

In the state of Colorado, several cities have passed local ordinances limiting or banning certain oil and gas activities, including hydraulic fracturing. These local rule-making initiatives have not significantly impacted the Company’s operations or development plans in the state to date. The ballot initiatives previously filed in the state seeking to transfer the authority to regulate all oil and gas activities, including hydraulic fracturing, to local governments were withdrawn in August 2014. Encana continues to work with state and local governments, academics and industry leaders to respond to hydraulic fracturing related concerns in Colorado. The Company recognizes that additional hydraulic fracturing ballot and/or local rule-making limiting or restricting oil and gas development activities are a possibility in the future and will continue to monitor and respond to these developments in 2015.

Encana is committed to and supports the disclosure of hydraulic fracturing chemical information. Encana participates in the FracFocus Chemical Disclosure Registry (the “Registry”) in the U.S. and the Alberta and British Columbia versions of the Registry. Encana works collaboratively with industry peers, trade associations, fluid suppliers and regulators to identify, develop and advance responsible hydraulic fracturing best practices. More information on hydraulic fracturing can be accessed on the Company’s website at www.encana.com.

Air quality regulations in the state of Colorado were amended in February 2014 to address ozone non-attainment in the state. The amended regulations establish new leak detection and repair requirements and hydrocarbon emissions standards for the oil and gas industry in the state. Encana has reviewed the new requirements and does not anticipate they will have a material impact on its Colorado operations.

38 Encana Corporation | Annual Report 2014

CLIMATE CHANGE REGULATIONS

A number of federal, provincial and state governments have announced intentions to regulate greenhouse gases (“GHG”) and certain other air emissions. While some jurisdictions have provided details on these regulations, it is anticipated that other jurisdictions will announce emission reduction plans in the future. As these federal and regional programs are under development, Encana is unable to predict the total impact of the potential regulations upon its business. Therefore, it is possible that the Company could face increases in operating and capital costs in order to comply with GHG emissions legislation. However, Encana will continue to work with governments to develop an approach to deal with climate change issues that protects the industry’s competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector.

The Alberta Government has set targets for GHG emission reductions. In March 2007, regulations were amended to require facilities that emit more than 100,000 tonnes of GHG emissions per year to reduce their emissions intensity by 12 percent from a regulated baseline starting July 1, 2007. To comply, companies can make operating improvements, purchase carbon offsets or make a C$15 per tonne contribution to an Alberta Climate Change and Emissions Management Fund. At present, Encana does not own or operate any facilities subject to the emissions regulation. The Company’s forecast cost of carbon associated with the Alberta regulations is not material to Encana and is being actively managed.

In British Columbia, effective July 1, 2008, a ‘revenue neutral carbon tax’ was applied to virtually all fossil fuels, including diesel, natural gas, coal, propane and home heating fuel. The tax applies to combustion emissions and to the purchase or use of fossil fuels within the province. The rate started at C$10 per tonne of carbon equivalent emissions and has risen to C$30 per tonne at present. The Company’s forecast cost of carbon associated with the British Columbia regulations is not material to Encana and is being actively managed.

The Canadian federal government has announced that it will align GHG emission reduction targets with the U.S. The Canadian federal government has taken a sector-specific approach and, while progress has been made working with industry and the provinces on the development of oil and gas sector-specific regulations, the federal government has not committed to a definitive timeline for implementation and/or release of legislation. Encana will continue to monitor these developments during 2015.

The U.S. federal government has noted climate change action as a priority for the current administration. On January 14, 2015, the Environmental Protection Agency (“EPA”) outlined a series of steps to address methane and volatile organic compound emissions from the oil and gas industry, including a new goal to reduce oil and gas methane emissions by 40 to 45 percent from 2012 levels by 2025. The reductions will be achieved through regulatory and voluntary measures which have not yet been announced. The EPA plans to propose this new rule and guidance in late summer 2015 with a final rule and guidance expected in 2016.

Encana intends to continue its activity to reduce its emissions intensity and improve its energy efficiency. The Company’s efforts with respect to emissions management are founded with a focus on energy efficiency, the development of technology to reduce GHG emissions and active involvement in the creation of industry best practices.

Encana has a proactive strategy for addressing the implications of emerging carbon regulations which is composed of three principal elements:

•

Active Cost Management. When regulations are implemented, a cost is placed on Encana’s emissions (or a portion thereof) and, while these are not material at this stage, they are being actively managed to ensure compliance. Factors such as effective emissions tracking and attention to fuel consumption help to support and drive the Company’s focus on cost reduction.

•

Anticipate and Respond to Price Signals. As regulatory regimes for GHG develop in the jurisdictions where Encana operates, inevitably price signals begin to emerge. The price of potential carbon reductions plays a role in the economics of the projects that are implemented. In response to the anticipated price of carbon, Encana is also attempting, where appropriate, to realize the associated value of its reduction projects.

•

Work with Industry Groups. Encana continues to work with governments, academics and industry leaders to develop and respond to emerging GHG regulations. By continuing to stay engaged in the debate on the most appropriate means to regulate these emissions, the Company gains useful knowledge that allows it to explore different strategies for managing its emissions and costs. These scenarios influence Encana’s long-range planning and its analyses on the implications of regulatory trends.

Encana monitors developments in emerging climate change policy and legislation, and considers the associated costs of carbon in its planning. Management and the Board review the impact of a variety of carbon constrained scenarios on its business plans, with a current price range from approximately $20 to $125 per tonne of emissions applied to a range of emissions coverage levels. Although uncertainty remains regarding potential future emissions regulation, Encana’s plan is to continue to assess and evaluate the cost of carbon relative to its investments across a range of scenarios.

Encana recognizes that there is a cost associated with carbon emissions. Encana is confident that GHG regulations and the cost of carbon at various price levels have been adequately considered as part of its business planning and scenarios analyses. Encana believes that the resource play strategy is an effective way to develop the resource, generate shareholder returns and coordinate overall environmental objectives with respect to carbon, air emissions, water and land. Encana is committed to transparency with its stakeholders and will keep them apprised of how these issues affect operations. Additional detail on Encana’s GHG emissions is available in the Sustainability Report that is available on the Company’s website at www.encana.com.

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CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

The Company’s President and Chief Executive Officer (“CEO”) and Executive Vice-President, Finance and Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that:

•

Material information relating to the Company is made known to the CEO and CFO by others; and

•

Information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.

Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s disclosure controls and procedures at the financial year end of the Company. Based on their evaluation, the officers have concluded that Encana’s disclosure controls and procedures were effective as at December 31, 2014.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting, which is a process designed by, or designed under the supervision of the CEO and CFO, and effected by the Board, Management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.

Under their supervision and with the participation of Management, including the CEO and CFO, an evaluation of the effectiveness of the Company’s internal control over financial reporting was conducted at December 31, 2014, based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, Management has concluded that the Company’s internal control over financial reporting was effectively designed and operating effectively as at that date.

Except for changes relating to the continuing integration of Athlon, as discussed below, there have been no changes in the Company’s internal control over financial reporting during the year ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the effectiveness of the internal control over financial reporting.

In accordance with Section 3.3(1) of National Instrument 52-109 and Rules 13a-15(f) and 15d-15(f) under the United States Securities and Exchange Act of 1934, as amended, Management has limited the scope and design and subsequent evaluation of internal controls over financial reporting to exclude the controls, policies and procedures of Athlon, acquired through a business combination on November 13, 2014. Summary financial information related to Athlon’s operations included in Encana’s Consolidated Financial Statements for the year ended December 31, 2014 is as follows:


($ millions)
Revenues	$	176
Net Earnings (Loss)		(3	)
Current Assets		198
Non-Current Assets		3,096
Current Liabilities		190
Non-Current Liabilities		148

LIMITATIONS OF THE EFFECTIVENESS OF CONTROLS

The Company’s control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements. Control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation and should not be expected to prevent all errors or fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP, an independent firm of chartered accountants, was appointed by a vote of shareholders at the Company’s last annual meeting to audit and provide independent opinions on both the Consolidated Financial Statements and the Company’s internal control over financial reporting as at December 31, 2014, as stated in their Auditor’s Report which is included in our audited Consolidated Financial Statements for the year ended December 31, 2014.

40 Encana Corporation | Annual Report 2014

ACCOUNTING POLICIES AND ESTIMATES

CRITICAL ACCOUNTING ESTIMATES

Management is required to make judgments, assumptions and estimates in applying its accounting policies and practices, which have a significant impact on the financial results of the Company. A summary of Encana’s significant accounting policies can be found in Note 1 to the Consolidated Financial Statements for the year ended December 31, 2014. The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to determining Encana’s financial results.

UPSTREAM ASSETS AND RESERVES

Encana follows U.S. GAAP full cost accounting for natural gas, oil and NGL activities. Reserves estimates can have a significant impact on net earnings, as they are a key input to the Company’s depletion, gain or loss and ceiling test impairment calculations. A downward revision in reserves estimates may increase depletion expense and may also result in a ceiling test impairment. A ceiling test impairment is recognized in net earnings when the carrying amount of a country cost centre exceeds the country cost centre ceiling. The carrying amount of a cost centre includes capitalized costs of proved oil and gas properties, net of accumulated depletion and the related deferred income taxes. The cost centre ceiling is the sum of the estimated after-tax future net cash flows from proved reserves as calculated under SEC requirements, using the 12-month average trailing prices and unescalated future development and production costs, discounted at 10 percent, plus unproved property costs. The 12-month average trailing price is calculated as the average of the price on the first day of each month within the trailing 12-month period. Any excess of the carrying amount over the calculated ceiling is recognized as an impairment in net earnings. During 2012, Encana recorded ceiling test impairments, which are discussed further in the Results of Operations section of this MD&A.

Annually, all of Encana’s natural gas, oil and NGL reserves and resources are evaluated and reported on by IQREs. The estimation of reserves is a subjective process. Estimates are based on engineering data, projected future rates of production, and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. Reserves estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery.

The Company believes that the discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are not indicative of the fair market value of Encana’s oil and gas properties or of the future net cash flows expected to be generated from such properties. The discounted after-tax future net cash flows do not consider the value of unproved properties, the value of probable or possible reserves or future changes in commodity prices. Encana manages its business using estimates of reserves and resources based on forecast prices and costs.

BUSINESS COMBINATIONS

Encana follows the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as a gain in net earnings. In determining fair value, Encana utilized valuation methodologies including the income approach.

The assumptions made in performing these valuations include discount rates, future commodity prices and costs, the timing of development activities, projections of oil and gas reserves, estimates to abandon and reclaim producing wells and tax amortization benefits available to a market participant. Any significant change in key assumptions may cause the acquisition accounting to be revised, including the recognition of additional goodwill or discount on acquisition.

The valuation of fair values are determined based on information that existed at the time of the acquisition, utilizing expectations and assumptions that would be available to and made by a market participant. However, there is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected. Changes in key assumptions and estimates can impact net earnings through ceiling test impairments, impairments of goodwill, or lower future operating results.

GOODWILL

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually at December 31. Goodwill and all other assets and liabilities are allocated to reporting units, which are Encana’s country cost centres. To assess impairment, the carrying amount of each reporting unit is determined and compared to the fair value of the reporting unit. If the carrying amount of the reporting unit is higher than its related fair value then goodwill is written down to the reporting unit’s implied fair value of goodwill. The implied fair value of goodwill is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit as if the reporting entity had been acquired in a business combination. Any excess of the carrying value of goodwill over the implied fair value of goodwill is recognized as an impairment and charged to net earnings. Subsequent measurement of goodwill is at cost less accumulated impairments.

The fair value used in the impairment test is based on estimates of discounted future cash flows which involves assumptions of natural gas and liquids reserves, including commodity prices, future costs and discount rates. Encana has assessed its goodwill for impairment at December 31, 2014 and has determined that no write-down is required.

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ASSET RETIREMENT OBLIGATION

Asset retirement obligations are those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, offshore production platforms and natural gas processing plants. The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of future cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost.

The asset retirement obligation is estimated by discounting the expected future cash flows of the settlement. The discounted cash flows are based on estimates of such factors as reserves lives, retirement costs, timing of settlements, credit-adjusted risk-free rates and inflation rates. These estimates will impact net earnings through accretion of the asset retirement obligation in addition to depletion of the asset retirement cost included in property, plant and equipment. Actual expenditures incurred are charged against the accumulated asset retirement obligation.

INCOME TAXES

Encana follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the enacted income tax rates and laws expected to apply when the assets are realized and liabilities are settled. Current income taxes are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates and laws enacted at the end of the reporting period. The effect of a change in the enacted tax rates or laws is recognized in net earnings in the period of enactment.

Deferred income tax assets are routinely assessed for realizability. If it is more likely than not that deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets. Encana considers available positive and negative evidence when assessing the realizability of deferred tax assets, including historic and expected future taxable earnings, available tax planning strategies and carry forward periods. The assumptions used in determining expected future taxable earnings are consistent with those used in the goodwill impairment assessment.

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

Encana recognizes the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. A recognized tax position is initially and subsequently measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon settlement with a taxing authority. Liabilities for unrecognized tax benefits that are not expected to be settled within the next 12 months are included in other liabilities and provisions.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through the income tax expense arising from the changes in deferred income tax assets or liabilities.

DERIVATIVE FINANCIAL INSTRUMENTS

As described in the Risk Management section of this MD&A, derivative financial instruments are used by Encana to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.

Derivative financial instruments are measured at fair value with changes in fair value recognized in net earnings. The fair values recorded in the Consolidated Balance Sheet reflect netting the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Realized gains or losses from financial derivatives related to natural gas and oil commodity prices are recognized in revenues as the contracts are settled. Realized gains or losses from financial derivatives related to power commodity prices are recognized in transportation and processing expense as the related power contracts are settled. Unrealized gains and losses are recognized in revenues and transportation and processing expense accordingly, at the end of each respective reporting period based on the changes in fair value of the contracts.

The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third party market indications and forecasts. The estimated fair value of financial assets and liabilities is subject to measurement uncertainty.

42 Encana Corporation | Annual Report 2014

RECENT ACCOUNTING PRONOUNCEMENTS

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

As of January 1, 2014, Encana adopted the following Accounting Standards Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”), which have not had a material impact on the Company’s Consolidated Financial Statements:

•

ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, clarifies guidance for the recognition, measurement and disclosure of liabilities resulting from joint and several liability arrangements. The amendments have been applied retrospectively.

•

ASU 2013-05, Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity, clarifies the applicable guidance for certain transactions that result in the release of the cumulative translation adjustment into net earnings. The amendments have been applied prospectively.

•

ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, clarifies that a liability related to an unrecognized tax benefit or portions thereof should be presented as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except under specific situations. The amendments have been applied prospectively.

NEW STANDARDS ISSUED NOT YET ADOPTED

As of January 1, 2015, Encana will be required to adopt ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which amends the criteria and expands the disclosures for reporting discontinued operations. Under the new criteria, only disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments will be applied prospectively and are not expected to have a material impact on the Company’s Consolidated Financial Statements.

As of January 1, 2016, Encana will be required to adopt ASU 2014-12, Compensation – Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. The standard requires a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will be applied prospectively and are not expected to have a material impact on the Company’s Consolidated Financial Statements.

As of January 1, 2017, Encana will be required to adopt ASU 2014-09, Revenue from Contracts with Customers under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, Revenue Recognition, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the standard on the Company’s Consolidated Financial Statements.

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NON-GAAP MEASURES

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers. 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: Cash Flow; Free Cash Flow; Operating Earnings; Upstream Operating Cash Flow, excluding Hedging; Operating Netback; Debt to Debt Adjusted Cash Flow; and Debt to Adjusted Capitalization. Management’s use of these measures is discussed further below.

CASH FLOW AND FREE CASH FLOW

Cash Flow is a non-GAAP measure commonly used in the oil and gas industry and by Encana to assist Management and investors in measuring the Company’s ability to finance capital programs and meet financial obligations. Cash Flow is defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and cash tax on sale of assets.

Free Cash Flow is a non-GAAP measure defined as Cash Flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.


	2014															2013															2012
($ millions)	Annual			Q4			Q3			Q2			Q1			Annual			Q4			Q3			Q2			Q1			Annual

Cash From (Used in) Operating Activities	$	2,667		$	261		$	696		$	767		$	943		$	2,289		$	462		$	935		$	554		$	338		$	3,107
(Add back) deduct:
Net change in other assets and liabilities		(43	)		(15	)		(11	)		(8	)		(9	)		(80	)		(21	)		(15	)		(22	)		(22	)		(78	)
Net change in non-cash working capital		(9	)		(141	)		155			119			(142	)		(179	)		(183	)		300			(81	)		(215	)		(323	)
Cash tax on sale of assets		(215	)		40			(255	)		—			—			(33	)		(11	)		(10	)		(8	)		(4	)		(29	)

Cash Flow	$	2,934		$	377		$	807		$	656		$	1,094		$	2,581		$	677		$	660		$	665		$	579		$	3,537
Deduct:
Capital investment		2,526			857			598			560			511			2,712			717			641			639			715			3,476

Free Cash Flow	$	408		$	(480	)	$	209		$	96		$	583		$	(131	)	$	(40	)	$	19		$	26		$	(136	)	$	61

OPERATING EARNINGS

Operating Earnings is a non-GAAP measure that adjusts Net Earnings Attributable to Common Shareholders by non-operating items that Management believes reduces the comparability of the Company’s underlying financial performance between periods. Operating Earnings is commonly used in the oil and gas industry and by Encana to provide investors with information that is more comparable between periods.

Operating Earnings is defined as Net Earnings Attributable to Common Shareholders excluding non-recurring or non-cash items that Management believes reduces the comparability of the Company’s financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/ losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.


	2014															2013															2012
($ millions)	Annual			Q4			Q3			Q2			Q1			Annual			Q4			Q3			Q2			Q1			Annual

Net Earnings (Loss) Attributable to Common Shareholders	$	3,392		$	198		$	2,807		$	271		$	116		$	236		$	(251	)	$	188		$	730		$	(431	)	$	(2,794	)

After-tax (addition) / deduction:

Unrealized hedging gain (loss)		306			341			160			8			(203	)		(232	)		(209	)		(89	)		332			(266	)		(1,002	)
Impairments		—			—			—			—			—			(16	)		—			(16	)		—			—			(3,188	)
Restructuring charges		(24	)		(4	)		(5	)		(5	)		(10	)		(64	)		(64	)		—			—			—			—
Non-operating foreign exchange gain (loss)		(407	)		(151	)		(218	)		156			(194	)		(282	)		(124	)		105			(162	)		(101	)		92
Gain (loss) on divestitures		2,523			(11	)		2,399			135			—			—			—			—			—			—			—
Income tax adjustments		(8	)		(12	)		190			(194	)		8			28			(80	)		38			313			(243	)		307

Operating Earnings	$	1,002		$	35		$	281		$	171		$	515		$	802		$	226		$	150		$	247		$	179		$	997

44 Encana Corporation | Annual Report 2014

UPSTREAM OPERATING CASH FLOW, EXCLUDING HEDGING

Upstream Operating Cash Flow, excluding Hedging is a non-GAAP measure that adjusts the Canadian and USA Operations revenues, net of royalties for production and mineral taxes, transportation and processing expense, operating expense and the impacts of realized hedging. Management monitors Upstream Operating Cash Flow, excluding Hedging as it reflects operating performance and measures the Company’s portfolio transition to higher margin production. Upstream Operating Cash Flow, excluding Hedging is reconciled to GAAP measures in the Results of Operations section of this MD&A. The table below totals Upstream Operating Cash Flow for Encana.


	2014													2013										2012
($ millions)	Annual			Q4		Q3		Q2			Q1			Annual		Q4		Q3		Q2		Q1		Annual
Upstream Operating Cash Flow
Canadian Operations	$	2,146		$	341	$	477	$	477		$	881		$	1,681	$	526	$	406	$	383	$	366	$	1,844
USA Operations		1,772			480		505		353			434			1,511		375		388		405		343		2,240

	$	3,918		$	821	$	982	$	800		$	1,315		$	3,192	$	901	$	794	$	788	$	709	$	4,084

(Add back) deduct:
Realized Hedging Gain (Loss)
Canadian Operations	$	(56	)	$	49	$	19	$	(49	)	$	(75	)	$	276	$	90	$	95	$	21	$	70	$	958
USA Operations		(25	)		78		11		(49	)		(65	)		264		83		77		30		74		1,195

	$	(81	)	$	127	$	30	$	(98	)	$	(140	)	$	540	$	173	$	172	$	51	$	144	$	2,153

Upstream Operating Cash Flow, excluding Hedging
Canadian Operations	$	2,202		$	292	$	458	$	496		$	956		$	1,405	$	436	$	311	$	362	$	296	$	886
USA Operations		1,797			402		494		402			499			1,247		292		311		375		269		1,045

	$	3,999		$	694	$	952	$	898		$	1,455		$	2,652	$	728	$	622	$	737	$	565	$	1,931

OPERATING NETBACK

Operating Netback is a common metric used in the oil and gas industry to measure operating performance by product. Operating Netbacks are calculated by determining product revenues, net of royalties and deducting costs associated with delivering the product to market, including production and mineral taxes, transportation and processing expenses and operating expenses. The Operating Netback calculation is shown in the Results of Operations section of this MD&A.

DEBT TO DEBT ADJUSTED CASH FLOW

Debt to Debt Adjusted Cash Flow is a non-GAAP measure monitored by Management as an indicator of the Company’s overall financial strength. Debt Adjusted Cash Flow is a non-GAAP measure defined as Cash Flow on a trailing 12-month basis excluding interest expense after tax.

Previously, Management monitored Net Debt to Debt Adjusted Cash Flow. Net Debt was defined as long-term debt, including current portion, less cash and cash equivalents.


($ millions)	2014		2013		2012

Debt	$	7,340	$	7,124	$	7,675

Cash Flow		2,934		2,581		3,537

Interest Expense, after tax		486		421		391

Debt Adjusted Cash Flow	$	3,420	$	3,002	$	3,928

Debt to Debt Adjusted Cash Flow		2.1x		2.4x		2.0x

LOGO

Annual Report 2014 | Encana Corporation 45

LOGO

DEBT TO ADJUSTED CAPITALIZATION

Debt to Adjusted Capitalization is a non-GAAP measure which adjusts capitalization for historical ceiling test impairments that were recorded as at December 31, 2011. Management monitors Debt to Adjusted Capitalization as a proxy for Encana’s financial covenant under its credit facility agreements 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)	2014			2013			2012
Debt	$	7,340		$	7,124		$	7,675

Total Shareholders’ Equity		9,685			5,147			5,295
Equity Adjustment for Impairments at December 31, 2011		7,746			7,746			7,746

Adjusted Capitalization	$	24,771		$	20,017		$	20,716

Debt to Adjusted Capitalization		30	%		36	%		37	%

ADVISORY

FORWARD-LOOKING STATEMENTS

In the interest of providing Encana shareholders and potential investors with information regarding the Company and its subsidiaries, including Management’s assessment of Encana’s and its subsidiaries’ future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “objective”, “strategy”, “strives”, “agreed to” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements in this document include, but are not limited to, statements with respect to:

•

the Company’s vision to be the leading North American resource play company and deliver strong operational and financial results

•

achieving the Company’s focus on developing its strong portfolio of resource plays producing natural gas, oil and NGLs

•

commitment to growing long-term shareholder value through a disciplined focus on generating profitable growth

•

pursuing its key business objectives of balancing its commodity mix, focusing capital investments in high return, scalable projects, maintaining portfolio flexibility, maximizing profitability through operating efficiencies, reducing costs and preserving balance sheet strength

•

the expected timing and closing date of the transaction with Veresen Midstream Limited Partnership and the expectation that regulatory approvals will be obtained and closing conditions satisfied

•

anticipated revenues and operating expenses

•

improving operating efficiencies, fostering technological innovation, lowering cost structures and the success of the resource play hub model

•

the anticipated proceeds from various joint venture, partnership and other agreements entered into by the Company, including their successful implementation, expected future benefits and the Company’s ability to fund future development costs associated with those agreements

•

statements with respect to future ceiling test impairments

•

anticipated dividends

•

anticipated oil, natural gas and NGLs prices

•

the expectation to continue to deliver shareholder value through commodity price cycles

•

the Company’s continued commitment to strong governance and corporate responsibility

•

anticipated production from Eagle Ford

•

projections contained in the 2015 Corporate Guidance (including estimates of cash flow including per share amounts, natural gas, oil and NGLs production, capital investment and its allocation, operating costs, sensitivities on price and their impact on cash flow and operating earnings, assumptions regarding oil, natural gas and NGLs prices and foreign exchange rates)

•

estimates of reserves and resources

•

projections relating to the adequacy of the Company’s provision for taxes and legal claims

•

the flexibility of capital spending plans and the source of funding therefor

•

anticipated access to capital markets and ability to meet financial obligations and finance growth

•

the benefits of the Company’s risk management program, including the impact of derivative financial instruments

•

projections that the Company has access to cash and cash equivalents and a range of funding at competitive rates

•

the Company’s ability to meet payment terms of its suppliers and be in compliance with all financial covenants under its credit facility agreements

•

the Company’s intention to settle vested RSUs in cash on the vesting date

46 Encana Corporation | Annual Report 2014

•

anticipated debt repayments and the ability to make such repayments

•

expected future interest expense savings associated with Athlon’s senior notes

•

expectations surrounding environmental legislation including regulations relating to carbon, air quality, water, land and hydraulic fracturing and the impact such regulations could have on the Company

•

anticipated flexibility to refinance maturing long-term debt or repay debt maturities from existing sources of liquidity

•

anticipated cash and cash equivalents

•

expectation to fund 2015 commitments from cash flow, cash and cash equivalents

•

the anticipated effect of the Company’s risk mitigation policies, systems, processes and insurance program

•

the Company’s ability to manage its Debt to Debt Adjusted Cash Flow and Debt to Adjusted Capitalization ratios

•

the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company and its financial statements

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the Company’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things:

•

volatility of, and assumptions regarding natural gas and liquids prices, including substantial or extended decline of the same and their adverse effect on the Company’s operations and financial condition and the value and amount of its reserves

•

assumptions based upon the Company’s current guidance

•

risks and uncertainties associated with announced but not completed transactions including the risk that the transactions may not be completed on a timely basis or at all

•

fluctuations in currency and interest rates

•

risk that the Company may not conclude divestitures of certain assets or other transactions or receive 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

•

product supply and demand

•

market competition

•

risks inherent in the Company’s and its subsidiaries’ marketing operations, including credit risks

•

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

•

marketing margins

•

potential disruption or unexpected technical difficulties in developing new facilities

•

unexpected cost increases or technical difficulties in constructing or modifying processing facilities

•

risks associated with technology

•

the Company’s ability to acquire or find additional reserves

•

hedging activities resulting in realized and unrealized losses

•

business interruption and casualty losses

•

risk of the Company not operating all of its properties and assets

•

counterparty risk

•

downgrade in credit rating and its adverse effects

•

liability for indemnification obligations to third parties

•

variability of dividends to be paid

•

the Company’s ability to generate sufficient cash flow from operations to meet its current and future obligations

•

the Company’s ability to access external sources of debt and equity capital

•

the timing and the costs of well and pipeline construction

•

the Company’s ability to secure adequate product transportation

•

changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations of such laws or regulations

•

political and economic conditions in the countries in which the Company operates; terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the Company

•

risk arising from price basis differential

•

risk arising from inability to enter into attractive hedges to protect the Company’s capital program

•

other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Encana

LOGO

Annual Report 2014 | Encana Corporation 47

LOGO

Although Encana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this document are made as of the date hereof and, except as required by law, Encana undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

Forward-looking information respecting anticipated 2015 cash flow for Encana is based upon, among other things, achieving average production for 2015 of between 1,600 MMcf/d and 1,700 MMcf/d of natural gas and 130 Mbbls/d to 150 Mbbls/d of liquids, commodity prices for natural gas and liquids based on NYMEX $3.00 per MMBtu and WTI of $50 per bbl, an estimated U.S./Canadian dollar exchange rate of 0.80 and a weighted average number of outstanding shares for Encana of approximately 741 million.

Assumptions relating to forward-looking statements generally include Encana’s current expectations and projections made in light of, and generally consistent with, its historical experience and its perception of historical trends, including the conversion of resources into reserves and production as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this document.

Encana is required to disclose events and circumstances that occurred during the period to which this MD&A relates that are reasonably likely to cause actual results to differ materially from material forward-looking statements for a period that is not yet complete that Encana has previously disclosed to the public and the expected differences thereto. Such disclosure can be found in Encana’s news release dated February 25, 2015, which is available on Encana’s website at www.encana.com, on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

OIL AND GAS INFORMATION

NI 51-101 of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. The Canadian protocol disclosure is contained in Appendix A and under “Narrative Description of the Business” in the Company’s AIF. Encana obtained an exemption dated January 4, 2011 from certain requirements of NI 51-101 to permit it to provide certain disclosure prepared in accordance with U.S. disclosure requirements, in addition to the Canadian protocol disclosure. The Company’s U.S. protocol disclosure is included in Note 26 (unaudited) to the Company’s Consolidated Financial Statements for the year ended December 31, 2014 and in Appendix D of the AIF.

Further, Encana obtained an exemption dated January 21, 2015 from certain requirements of NI 51-101 to permit it to use the definition of “product type” contained in the amendments to NI 51-101, published by the securities regulatory authority in each of the jurisdictions of Canada on December 4, 2014 that are anticipated to come into force on July 1, 2015, as it relates to its Canadian protocol disclosure contained in Appendix A of the AIF.

A description of the primary differences between the disclosure requirements under the Canadian standards and under the U.S. standards is set forth under the heading “Reserves and Other Oil and Gas Information” in the AIF.

NATURAL GAS, OIL AND NGLS CONVERSIONS

In this document, certain natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of 6:1 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.

Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

PLAY AND RESOURCE PLAY

Play is a term used by Encana which encompasses resource plays, geological formations and conventional plays. Resource play is a term used by Encana to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk and lower average decline rate.

ADDITIONAL INFORMATION

Further information regarding Encana Corporation, including its AIF, can be accessed under the Company’s public filings found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov and on the Company’s website at www.encana.com.

48 Encana Corporation | Annual Report 2014

MANAGEMENT

REPORT

Management’s Responsibility for Consolidated Financial Statements

The accompanying Consolidated Financial Statements of Encana Corporation (the “Company”) are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in United States dollars in accordance with generally accepted accounting principles in the United States and include certain estimates that reflect Management’s best judgments.

The Company’s Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee, which has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes-Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets at least on a quarterly basis.

Management’s Assessment of Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. The internal control system was designed to provide reasonable assurance to the Company’s Management regarding the preparation and presentation of the Consolidated Financial Statements.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the design and effectiveness of the Company’s internal control over financial reporting as at December 31, 2014. In making its assessment, Management has used the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Based on our evaluation, Management has concluded that the Company’s internal control over financial reporting was effectively designed and operating effectively as at that date.

Management has excluded Athlon Energy Inc. from its assessment of internal control over financial reporting as at December 31, 2014 because it was acquired by the Company through a business combination during 2014. Assets attributable to Athlon Energy Inc. as of December 31, 2014 represented approximately 13 percent of the Company’s total assets as of December 31, 2014, and revenues attributable to Athlon Energy Inc. for the period from November 13, 2014 to December 31, 2014 represented approximately 2 percent of the Company’s total revenues for the year ended December 31, 2014.

PricewaterhouseCoopers LLP, an independent firm of chartered accountants, was appointed by a vote of shareholders at the Company’s last annual meeting to audit and provide independent opinions on both the Consolidated Financial Statements and the Company’s internal control over financial reporting as at December 31, 2014, as stated in their Auditor’s Report. PricewaterhouseCoopers LLP has provided such opinions.




Douglas J. Suttles				Sherri A. Brillon
President & Chief Executive Officer				Executive Vice-President & Chief Financial Officer

March 3, 2015

Annual Report 2014 | Encana Corporation 49

AUDITOR’S

REPORT

INDEPENDENT AUDITOR’S REPORT

To the Shareholders of Encana Corporation

We have completed an integrated audit of Encana Corporation’s 2014, 2013 and 2012 Consolidated Financial Statements and its internal control over financial reporting as at December 31, 2014. Our opinions, based on our audits, are presented below.

Report on the Consolidated Financial Statements

We have audited the accompanying Consolidated Financial Statements of Encana Corporation, which comprise the Consolidated Balance Sheet as at December 31, 2014 and December 31, 2013 and the Consolidated Statements of Earnings, Comprehensive Income, Changes in Shareholders’ Equity and Cash Flows for each of the three years in the period ended December 31, 2014, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America and for such internal control as management determines is necessary to enable the preparation of Consolidated Financial Statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these Consolidated Financial Statements based on our audits. We conducted our audits as at December 31, 2014 and December 31, 2013 and for the years then ended in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free from material misstatement. Canadian generally accepted auditing standards also require that we comply with ethical requirements.

An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the Consolidated Financial Statements.

Opinion

In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the financial position of Encana Corporation and its subsidiaries as at December 31, 2014 and December 31, 2013 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014 in accordance with accounting principles generally accepted in the United States of America.

50 Encana Corporation | Annual Report 2014

LOGO

REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

We have also audited Encana Corporation and its subsidiaries’ internal control over financial reporting as at December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

Management’s Responsibility for Internal Control over Financial Reporting

Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Assessment of Internal Control over Financial Reporting.

Auditor’s Responsibility

Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances.

We believe that our audit provides a reasonable basis for our audit opinion on the company’s internal control over financial reporting.

Definition of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Inherent Limitations

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Athlon Energy Inc. from its assessment of internal control over financial reporting as at December 31, 2014 because it was acquired by the Company through a business combination during 2014. We have also excluded Athlon Energy Inc. from our audit of internal control over financial reporting. Assets attributable to Athlon Energy Inc. as of December 31, 2014 represented approximately 13 percent of the Company’s total assets as of December 31, 2014, and revenues attributable to Athlon Energy Inc. for the period from November 13, 2014 to December 31, 2014 represented approximately 2 percent of the Company’s total revenues for the year ended December 31, 2014.

Opinion

In our opinion, Encana Corporation and its subsidiaries maintained, in all material respects, effective internal control over financial reporting as at December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta, Canada

March 3, 2015

Annual Report 2014 | Encana Corporation 51

CONSOLIDATED STATEMENT

OF EARNINGS


For the years ended December 31 ($ millions, except per share amounts)			2014			2013			2012

Revenues, Net of Royalties	(Note 2	)	$	8,019		$	5,858		$	5,160
Expenses	(Note 2	)
Production and mineral taxes				133			134			105
Transportation and processing				1,505			1,476			1,231
Operating				735			859			794
Purchased product				1,191			441			349
Depreciation, depletion and amortization				1,745			1,565			1,956
Impairments	(Note 9	)		—			21			4,695
Accretion of asset retirement obligation	(Note 15	)		52			53			53
Administrative	(Note 19	)		327			439			392
Interest	(Note 5	)		654			563			522
Foreign exchange (gain) loss, net	(Note 6	)		403			325			(107	)
(Gain) loss on divestitures	(Notes 4,18	)		(3,426	)		(7	)		—
Other	(Note 3	)		71			1			1

				3,390			5,870			9,991

Net Earnings (Loss) Before Income Tax				4,629			(12	)		(4,831	)
Income tax expense (recovery)	(Note 7	)		1,203			(248	)		(2,037	)

Net Earnings (Loss)				3,426			236			(2,794	)
Net earnings attributable to noncontrolling interest	(Note 18	)		(34	)		—			—

Net Earnings (Loss) Attributable to Common Shareholders			$	3,392		$	236		$	(2,794	)


Net Earnings (Loss) per Common Share
Basic & Diluted	(Note 16	)	$	4.58		$	0.32		$	(3.79	)

CONSOLIDATED STATEMENT

OF COMPREHENSIVE INCOME


For the years ended December 31 ($ millions)			2014			2013			2012

Net Earnings (Loss)			$	3,426		$	236		$	(2,794	)
Other Comprehensive Income (Loss), Net of Tax
Foreign currency translation adjustment	(Note 17	)		22			(46	)		81
Pension and other post-employment benefit plans	(Notes 17,21	)		(17	)		60			13

Other Comprehensive Income				5			14			94

Comprehensive Income (Loss)				3,431			250			(2,700	)

Comprehensive Income Attributable to Noncontrolling Interest	(Note 18	)		(34	)		—			—

Comprehensive Income (Loss) Attributable to Common Shareholders			$	3,397		$	250		$	(2,700	)

See accompanying Notes to Consolidated Financial Statements

52 Encana Corporation | Annual Report 2014

CONSOLIDATED

BALANCE SHEET


As at December 31 ($ millions)			2014			2013

Assets
Current Assets
Cash and cash equivalents			$	338		$	2,566
Accounts receivable and accrued revenues	(Note 8	)		1,307			988
Risk management	(Note 23	)		707			56
Income tax receivable				509			562
Deferred income taxes	(Note 7	)		—			118

				2,861			4,290

Property, Plant and Equipment, at cost:	(Note 9	)
Natural gas and oil properties, based on full cost accounting
Proved properties				42,615			51,603
Unproved properties				6,133			1,068
Other				2,711			3,148

Property, plant and equipment				51,459			55,819
Less: Accumulated depreciation, depletion and amortization				(33,444	)		(45,784	)

Property, plant and equipment, net	(Note 2	)		18,015			10,035
Cash in Reserve				73			10
Other Assets	(Note 10	)		394			526
Risk Management	(Note 23	)		65			204
Deferred Income Taxes	(Note 7	)		296			939
Goodwill	(Notes 2, 3, 4, 11, 18	)		2,917			1,644

	(Note 2	)	$	24,621		$	17,648


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities	(Note 12	)	$	2,243		$	1,895
Income tax payable				15			29
Risk management	(Note 23	)		20			25
Current portion of long-term debt	(Note 13	)		—			1,000
Deferred income taxes	(Note 7	)		128			3

				2,406			2,952

Long-Term Debt	(Note 13	)		7,340			6,124
Other Liabilities and Provisions	(Note 14	)		2,484			2,520
Risk Management	(Note 23	)		7			5
Asset Retirement Obligation	(Note 15	)		870			900
Deferred Income Taxes	(Note 7	)		1,829			—

				14,936			12,501

Commitments and Contingencies	(Note 25	)
Shareholders’ Equity
Share capital – authorized unlimited common shares, without par value 2014 issued and outstanding: 741.2 million shares (2013: 740.9 million shares)	(Note 16	)		2,450			2,445
Paid in surplus	(Notes 16, 18, 20	)		1,358			15
Retained earnings				5,188			2,003
Accumulated other comprehensive income	(Note 17	)		689			684

Total Shareholders’ Equity				9,685			5,147

			$	24,621		$	17,648

See accompanying Notes to Consolidated Financial Statements

Approved by the Board of Directors




Clayton H. Woitas				Jane L. Peverett
Director				Director

Annual Report 2014 | Encana Corporation 53

CONSOLIDATED STATEMENT OF

CHANGES IN SHAREHOLDERS’ EQUITY


For the year ended December 31, 2014 ($ millions)			Share Capital			Paid in Surplus			Retained Earnings			Accumulated Other Comprehensive Income		Non- Controlling Interest			Total Shareholders’ Equity

Balance, December 31, 2013			$	2,445		$	15		$	2,003		$	684	$	—		$	5,147
Share-Based Compensation	(Note 20	)		—			(2	)		—			—		—			(2	)
Net Earnings (Loss)				—			—			3,392			—		34			3,426
Dividends on Common Shares	(Note 16	)		—			—			(207	)		—		—			(207	)
Common Shares Issued Under Dividend Reinvestment Plan	(Note 16	)		5			—			—			—		—			5
Other Comprehensive Income	(Note 17	)		—			—			—			5		—			5
Sale of Noncontrolling Interest	(Note 18	)		—			1,345			—			—		117			1,462
Distributions to Noncontrolling Interest Owners	(Note 18	)		—			—			—			—		(18	)		(18	)
Sale of Investment in PrairieSky	(Note 18	)		—			—			—			—		(133	)		(133	)

Balance, December 31, 2014			$	2,450		$	1,358		$	5,188		$	689	$	—		$	9,685


For the year ended December 31, 2013 ($ millions)			Share Capital			Paid in Surplus			Retained Earnings			Accumulated Other Comprehensive Income		Non- Controlling Interest			Total Shareholders’ Equity

Balance, December 31, 2012			$	2,354		$	10		$	2,261		$	670	$	—		$	5,295
Share-Based Compensation	(Note 20	)		—			3			—			—		—			3
Net Earnings (Loss)				—			—			236			—		—			236
Common Shares Cancelled	(Note 16	)		(2	)		2			—			—		—			—
Dividends on Common Shares	(Note 16	)		—			—			(494	)		—		—			(494	)
Common Shares Issued Under Dividend Reinvestment Plan	(Note 16	)		93			—			—			—		—			93
Other Comprehensive Income	(Note 17	)		—			—			—			14		—			14

Balance, December 31, 2013			$	2,445		$	15		$	2,003		$	684	$	—		$	5,147


For the year ended December 31, 2012 ($ millions)			Share Capital			Paid in Surplus			Retained Earnings			Accumulated Other Comprehensive Income		Non- Controlling Interest			Total Shareholders’ Equity

Balance, December 31, 2011			$	2,354		$	5		$	5,643		$	576	$	—		$	8,578
Share-Based Compensation	(Note 20	)		—			5			—			—		—			5
Net Earnings (Loss)				—			—			(2,794	)		—		—			(2,794	)
Dividends on Common Shares	(Note 16	)		—			—			(588	)		—		—			(588	)
Other Comprehensive Income				—			—			—			94		—			94

Balance, December 31, 2012			$	2,354		$	10		$	2,261		$	670	$	—		$	5,295

See accompanying Notes to Consolidated Financial Statements

54 Encana Corporation | Annual Report 2014

CONSOLIDATED STATEMENT

OF CASH FLOWS


For the years ended December 31 ($ millions)			2014			2013			2012

Operating Activities
Net earnings (loss)			$	3,426		$	236		$	(2,794	)
Depreciation, depletion and amortization				1,745			1,565			1,956
Impairments	(Note 9	)		—			21			4,695
Accretion of asset retirement obligation	(Note 15	)		52			53			53
Deferred income taxes	(Note 7	)		960			(57	)		(1,837	)
Unrealized (gain) loss on risk management	(Note 23	)		(444	)		345			1,465
Unrealized foreign exchange (gain) loss	(Note 6	)		440			330			(112	)
(Gain) loss on divestitures	(Notes 4,18	)		(3,426	)		(7	)		—
Other				(34	)		62			82
Net change in other assets and liabilities				(43	)		(80	)		(78	)
Net change in non-cash working capital	(Note 24	)		(9	)		(179	)		(323	)

Cash From (Used in) Operating Activities				2,667			2,289			3,107


Investing Activities
Capital expenditures	(Note 2	)		(2,526	)		(2,712	)		(3,476	)
Acquisitions	(Note 4	)		(3,016	)		(184	)		(379	)
Corporate acquisition	(Note 3	)		(5,962	)		—			—
Proceeds from divestitures	(Note 4	)		4,345			705			4,043
Proceeds from sale of investment in PrairieSky	(Notes 4,18	)		2,172			—			—
Cash in reserve				(63	)		44			415
Net change in investments and other				321			252			(242	)

Cash From (Used in) Investing Activities				(4,729	)		(1,895	)		361


Financing Activities
Issuance of revolving long-term debt	(Notes 13,23	)		1,277			—			1,721
Repayment of revolving long-term debt	(Note 3	)		(335	)		—			(1,724	)
Repayment of long-term debt	(Note 13	)		(2,152	)		(500	)		(503	)
Dividends on common shares	(Note 16	)		(202	)		(401	)		(588	)
Proceeds from sale of noncontrolling interest	(Note 18	)		1,462			—			—
Distributions to noncontrolling interest owners	(Note 18	)		(18	)		—			—
Capital lease payments and other financing arrangements	(Note 9	)		(71	)		(8	)		(17	)

Cash From (Used in) Financing Activities				(39	)		(909	)		(1,111	)

Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency				(127	)		(98	)		22

Increase (Decrease) in Cash and Cash Equivalents				(2,228	)		(613	)		2,379
Cash and Cash Equivalents, Beginning of Year				2,566			3,179			800

Cash and Cash Equivalents, End of Year			$	338		$	2,566		$	3,179


Cash, End of Year			$	142		$	161		$	92
Cash Equivalents, End of Year				196			2,405			3,087

Cash and Cash Equivalents, End of Year			$	338		$	2,566		$	3,179


Supplementary Cash Flow Information	(Note 24	)

See accompanying Notes to Consolidated Financial Statements

Annual Report 2014 | Encana Corporation 55

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A) NATURE OF OPERATIONS

Encana Corporation and its subsidiaries (“Encana” or the “Company”) are in the business of the exploration for, the development of, and the production and marketing of natural gas, oil and natural gas liquids (“NGLs”). The term liquids is used to represent Encana’s oil, NGLs and condensate.

B) BASIS OF PRESENTATION

The Consolidated Financial Statements include the accounts of Encana and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are expressed in United States (“U.S.”) dollars. Encana’s financial results are consolidated in Canadian dollars; however, the Company has adopted the U.S. dollar as its reporting currency to facilitate a more direct comparison to other North American oil and gas companies. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.

C) PRINCIPLES OF CONSOLIDATION

The Consolidated Financial Statements include the accounts of Encana and entities in which it holds a controlling interest. The noncontrolling interest represented the third party equity ownership in a former consolidated subsidiary, PrairieSky Royalty Ltd. (“PrairieSky”). See Note 18 for further details regarding the noncontrolling interest. As of September 26, 2014, Encana no longer holds an interest in PrairieSky. All intercompany balances and transactions are eliminated on consolidation. For upstream joint interest operations where Encana retains an undivided interest in jointly owned property, the Company records its proportionate share of assets, liabilities, revenues and expenses. Investments in non-controlled entities over which Encana has the ability to exercise significant influence are accounted for using the equity method.

D) FOREIGN CURRENCY TRANSLATION

Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings. Foreign currency revenues and expenses are translated at the rates of exchange in effect at the time of the transaction.

Assets and liabilities of foreign operations are translated at period end exchange rates, while the related revenues and expenses are translated using average rates over the period. Translation gains and losses relating to the foreign operations are included in accumulated other comprehensive income (“AOCI”). Recognition of Encana’s accumulated translation gains and losses into net earnings occurs upon complete or substantially complete liquidation of the Company’s investment in the foreign operation.

For financial statement presentation, assets and liabilities are translated into the reporting currency at period end exchange rates, while revenues and expenses are translated using average rates over the period. Gains and losses relating to the financial statement translation are included in AOCI.

E) USE OF ESTIMATES

Preparation of the Consolidated Financial Statements in conformity with U.S. GAAP requires Management to make informed estimates and assumptions and use judgments that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future events occur.

Significant items subject to estimates and assumptions are:

•

Estimates of proved reserves and related future cash flows used for depletion and ceiling test impairment calculations

•

Estimated fair value of long-term assets used for impairment calculations

•

Fair value of reporting units used for the assessment of goodwill

•

Estimates of future taxable earnings used to assess the realizable value of deferred tax assets

•

Fair value of asset retirement obligations and costs

•

Fair value of derivative instruments

•

Fair value attributed to assets acquired and liabilities assumed in business combinations

•

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate

•

Accruals for long-term performance-based compensation arrangements, including whether or not the performance criteria will be met and measurement of the ultimate payout amount

•

Recognized values of pension assets and obligations, as well as the pension costs charged to net earnings, depend on certain actuarial and economic assumptions

•

Accruals for legal claims, environmental risks and exposures

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F) REVENUE RECOGNITION

Revenues associated with Encana’s natural gas and liquids are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Realized gains and losses from the Company’s financial derivatives related to natural gas and oil commodity prices are recognized in revenue when the contract is settled. Unrealized gains and losses related to these contracts are recognized in revenue based on the changes in fair value of the contracts at the end of the respective periods.

Market optimization revenues and purchased product expenses are recorded on a gross basis when Encana takes title to the product and has the risks and rewards of ownership. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided where Encana acts as agent are recorded as the services are provided.

G) PRODUCTION AND MINERAL TAXES

Costs paid by Encana to certain mineral and non-mineral interest owners based on production of natural gas and liquids are recognized when the product is produced.

H) TRANSPORTATION AND PROCESSING

Costs paid by Encana for the transportation and processing of natural gas and liquids are recognized when the product is delivered and the services provided.

I) OPERATING

Operating costs paid by Encana for oil and gas properties in which the Company has a working interest. Expenses are net of amounts capitalized in accordance with the full cost method of accounting.

J) EMPLOYEE BENEFIT PLANS

The Company sponsors defined contribution and defined benefit plans, providing pension and other post-employment benefits to its employees in Canada and the U.S. As of January 1, 2003, the defined benefit pension plan was closed to new entrants.

Pension expense for the defined contribution pension plan is recorded as the benefits are earned by the employees covered by the plans. Encana accrues for its obligations under its employee defined benefit plans, net of plan assets. The cost of defined benefit pensions and other post-employment benefits is actuarially determined using the projected benefit method based on length of service and reflects Management’s best estimate of salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on historical and projected rates of return for assets in the investment plan portfolio. The actual return is based on the fair value of plan assets. The projected benefit obligation is discounted using the market interest rate on high-quality corporate debt instruments as at the measurement date.

Pension expense for the defined benefit pension plan includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments, the amortization of prior service costs, and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. Amortization is on a straight-line basis over a period covering the expected average remaining service lives of employees covered by the plans. Actuarial gains and losses related to the change in the over-funded or under-funded status of the defined benefit pension plan and other post-employment benefit plans are recognized in other comprehensive income.

K) INCOME TAXES

Deferred income tax assets are routinely assessed for realizability. If it is more likely than not that deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets. Encana considers available positive and negative evidence when assessing the realizability of deferred tax assets including historic and expected future taxable earnings, available tax planning strategies and carry forward periods. The assumptions used in determining expected future taxable earnings are consistent with those used in the goodwill impairment assessment.

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L) EARNINGS PER SHARE AMOUNTS

Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per common share amounts are calculated giving effect to the potential dilution that would occur if stock options were exercised or other contracts to issue common shares were exercised, fully vested, or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to repurchase common shares at the average market price.

M) CASH AND CASH EQUIVALENTS

Cash and cash equivalents include cash on hand and short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased. Outstanding disbursements issued in excess of applicable bank account balances are excluded from cash and cash equivalents and are recorded in accounts payable and accrued liabilities. Cash in reserve represents cash amounts segregated or held in escrow which are not available for general operating use.

N) PROPERTY, PLANT AND EQUIPMENT

UPSTREAM

Encana uses the full cost method of accounting for its acquisition, exploration and development activities. Under this method, all costs directly associated with the acquisition of, the exploration for, and the development of natural gas and liquids reserves are capitalized on a country-by-country cost centre basis. Capitalized costs exclude costs relating to production, general overhead or similar activities.

Under the full cost method of accounting, the carrying amount of Encana’s natural gas and oil properties within each country cost centre is subject to a ceiling test performed quarterly. A ceiling test impairment is recognized in net earnings when the carrying amount of a country cost centre exceeds the country cost centre ceiling. The carrying amount of a cost centre includes capitalized costs of proved oil and gas properties, net of accumulated depletion and the related deferred income taxes.

The cost centre ceiling is the sum of the estimated after-tax future net cash flows from proved reserves, using the 12-month average trailing prices and unescalated future development and production costs, discounted at 10 percent, plus unproved property costs. The 12-month average trailing price is calculated as the average of the price on the first day of each month within the trailing 12-month period. Any excess of the carrying amount over the calculated ceiling amount is recognized as an impairment in net earnings.

Capitalized costs accumulated within each cost centre are depleted using the unit-of-production method based on proved reserves. Depletion is calculated using the capitalized costs, including estimated retirement costs, plus the undiscounted future expenditures to be incurred in developing proved reserves.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed separately for impairment on a quarterly basis. Costs that have been impaired are included in the costs subject to depletion within the full cost pool.

Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of gain or loss unless the deduction significantly alters the relationship between capitalized costs and proved reserves in the cost centre, in which case a gain or loss is recognized in net earnings. Generally, a gain or loss on a divestiture would be recognized when 25 percent or more of the Company’s proved reserves quantities in a particular country are sold. For divestitures that result in the recognition of a gain or loss on the sale and constitute a business, goodwill is allocated to the divestiture.

CORPORATE

Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 25 years. Costs associated with The Bow office building are carried at cost and depreciated on a straight-line basis over the 60-year estimated life of the building. Assets under construction are not subject to depreciation until put into use. Land is carried at cost.

O) CAPITALIZATION OF COSTS

Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Interest is capitalized during the construction phase of major development projects.

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P) BUSINESS COMBINATIONS

Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at their fair value at the date of acquisition. Deferred taxes are recognized for any differences between the fair value of net assets acquired and their tax bases. Any excess of the purchase price over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price below the fair value of the net assets acquired is recorded as a gain in net earnings. Associated transaction costs are expensed when incurred.

Q) GOODWILL

R) IMPAIRMENT OF LONG-TERM ASSETS

The carrying value of long-term assets, excluding goodwill and upstream assets included in property, plant and equipment, are assessed for impairment when indicators suggest that the carrying value of an asset or asset group may not be recoverable. If the carrying amount exceeds the sum of the undiscounted cash flows expected to result from the continued use and eventual disposition of the asset or asset group, an impairment is recognized for the excess of the carrying amount over its estimated fair value.

S) ASSET RETIREMENT OBLIGATION

Amortization of asset retirement costs is included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset retirement obligations resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.

Actual expenditures incurred are charged against the accumulated asset retirement obligation.

T) STOCK-BASED COMPENSATION

Obligations for payments of cash or common shares under Encana’s stock-based compensation plans are accrued over the vesting period, net of forfeitures, using fair values. Fair values are determined using observable share prices and/or pricing models such as the Black-Scholes-Merton option-pricing model. For equity-settled stock-based compensation plans, fair values are determined at the grant date and are recognized over the vesting period as compensation costs with a corresponding credit to shareholders’ equity. For cash-settled stock-based compensation plans, fair values are determined at each reporting date and periodic changes are recognized as compensation costs, with a corresponding change to liabilities.

Obligations for payments for share units of Cenovus Energy Inc. (“Cenovus”) held by Encana employees were accrued as compensation costs based on the fair value of the financial liability.

U) LEASES

Leases entered into for the use of an asset are classified as either capital or operating leases. Capital leases transfer to the Company substantially all of the risks and benefits incidental to ownership of the leased item. Capital leases are capitalized upon commencement of the lease term at the lower of the fair value of the leased asset or the present value of the minimum lease payments. Capitalized leased assets are amortized over the estimated useful life of the asset if the lease arrangement contains a bargain purchase option or ownership of the leased asset transfers at the end of the lease term. Otherwise, the leased assets are amortized over the lease term. Amortization of capitalized leased assets is included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. All other leases are classified as operating leases and the payments are recognized on a straight-line basis over the lease term.

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V) FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques include the market, income, and cost approach. The market approach uses information generated by market transactions involving identical or comparable assets or liabilities; the income approach converts estimated future amounts to a present value; the cost approach is based on the amount that currently would be required to replace an asset.

Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair value hierarchy are as follows:

•

Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities, such as exchange-traded commodity derivatives.

•

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quoted market prices for similar assets or liabilities in active markets or other market corroborated inputs.

•

Level 3 – Inputs that are not observable from objective sources, such as forward prices supported by little or no market activity or internally developed estimates of future cash flows used in a present value model.

In determining fair value, the Company utilizes the most observable inputs available. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair value measurement is characterized based on the lowest level of input that is significant to the fair value measurement.

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated Balance Sheet approximates fair value. The fair value of long-term debt is disclosed in Note 13. Fair value information related to pension plan assets is included in Note 21. Recurring fair value measurements are performed for risk management assets and liabilities and for share units issued as part of the Split Transaction, as discussed in Notes 16 and 22.

Certain non-financial assets and liabilities are initially measured at fair value, such as asset retirement obligations and assets and liabilities acquired in business combinations or certain non-monetary exchange transactions.

W) RISK MANAGEMENT ASSETS AND LIABILITIES

Risk management assets and liabilities are derivative financial instruments used by Encana to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors (“Board”). The Company’s policy is not to utilize derivative financial instruments for speculative purposes.

Derivative instruments that do not qualify for the normal purchases and sales exemption are measured at fair value with changes in fair value recognized in net earnings. The fair values recorded in the Consolidated Balance Sheet reflect netting the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Realized gains or losses from financial derivatives related to natural gas and oil commodity prices are recognized in revenues as the contracts are settled. Realized gains or losses from financial derivatives related to power commodity prices are recognized in transportation and processing expense as the related power contracts are settled. Unrealized gains and losses are recognized in revenues and transportation and processing expense accordingly, at the end of each respective reporting period based on the changes in fair value of the contracts.

X) COMMITMENTS AND CONTINGENCIES

Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

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Y) RECENT ACCOUNTING PRONOUNCEMENTS

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

On January 1, 2014, Encana adopted the following Accounting Standards Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”), which have not had a material impact on the Company’s Consolidated Financial Statements:

•

ASU 2013-04, “Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”, clarifies guidance for the recognition, measurement and disclosure of liabilities resulting from joint and several liability arrangements. The amendments have been applied retrospectively.

•

ASU 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity”, clarifies the applicable guidance for certain transactions that result in the release of the cumulative translation adjustment into net earnings. The amendments have been applied prospectively.

•

ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists”, clarifies that a liability related to an unrecognized tax benefit or portions thereof should be presented as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except under specific situations. The amendments have been applied prospectively.

NEW STANDARDS ISSUED NOT YET ADOPTED

•

As of January 1, 2015, Encana will be required to adopt ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”, which amends the criteria and expands the disclosures for reporting discontinued operations. Under the new criteria, only disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments will be applied prospectively and are not expected to have a material impact on the Company’s Consolidated Financial Statements.

•

As of January 1, 2016, Encana will be required to adopt ASU 2014-12, “Compensation – Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period”. The standard requires that a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will be applied prospectively and are not expected to have a material impact on the Company’s Consolidated Financial Statements.

•

As of January 1, 2017, Encana will be required to adopt ASU 2014-09, “Revenue from Contracts with Customers” under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, “Revenue Recognition”, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the standard on the Company’s Consolidated Financial Statements.

2. SEGMENTED INFORMATION

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

•

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

•

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

•

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

Annual Report 2014 | Encana Corporation 61

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RESULTS OF OPERATIONS

SEGMENT AND GEOGRAPHIC INFORMATION


	Canadian Operations							USA Operations							Market Optimization
For the years ended December 31	2014		2013		2012			2014		2013		2012			2014		2013		2012

Revenues, Net of Royalties	$	3,310	$	2,824	$	2,760		$	2,902	$	2,763	$	3,365		$	1,248	$	512	$	419

Expenses
Production and mineral taxes		15		15		9			118		119		96			—		—		—
Transportation and processing		835		756		555			658		722		652			—		—		—
Operating		314		372		352			354		411		377			39		38		48
Purchased product		—		—		—			—		—		—			1,191		441		349

		2,146		1,681		1,844			1,772		1,511		2,240			18		33		22
Depreciation, depletion and amortization		625		601		748			992		818		1,102			4		12		12
Impairments		—		—		1,822			—		—		2,842			—		—		—

	$	1,521	$	1,080	$	(726	)	$	780	$	693	$	(1,704	)	$	14	$	21	$	10


	Corporate & Other								Consolidated
	2014		2013			2012			2014			2013			2012

Revenues, Net of Royalties	$	559	$	(241	)	$	(1,384	)	$	8,019		$	5,858		$	5,160

Expenses
Production and mineral taxes		—		—			—			133			134			105
Transportation and processing		12		(2	)		24			1,505			1,476			1,231
Operating		28		38			17			735			859			794
Purchased product		—		—			—			1,191			441			349

		519		(277	)		(1,425	)		4,455			2,948			2,681
Depreciation, depletion and amortization		124		134			94			1,745			1,565			1,956
Impairments		—		21			31			—			21			4,695

	$	395	$	(432	)	$	(1,550	)		2,710			1,362			(3,970	)


Accretion of asset retirement obligation										52			53			53
Administrative										327			439			392
Interest										654			563			522
Foreign exchange (gain) loss, net										403			325			(107	)
(Gain) loss on divestitures										(3,426	)		(7	)		—
Other										71			1			1

										(1,919	)		1,374			861

Net Earnings (Loss) Before Income Tax										4,629			(12	)		(4,831	)
Income tax expense (recovery)										1,203			(248	)		(2,037	)

Net Earnings (Loss)										3,426			236			(2,794	)
Net earnings attributable to noncontrolling interest										(34	)		—			—

Net Earnings (Loss) Attributable to Common Shareholders									$	3,392		$	236		$	(2,794	)

62 Encana Corporation | Annual Report 2014

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RESULTS OF OPERATIONS

INTERSEGMENT INFORMATION


	Market Optimization
	Marketing Sales						Upstream Eliminations									Total
For the years ended December 31	2014		2013		2012		2014			2013			2012			2014		2013		2012

Revenues, Net of Royalties	$	7,371	$	5,662	$	4,260	$	(6,123	)	$	(5,150	)	$	(3,841	)	$	1,248	$	512	$	419

Expenses
Transportation and processing		458		516		528		(458	)		(516	)		(528	)		—		—		—
Operating		62		75		84		(23	)		(37	)		(36	)		39		38		48
Purchased product		6,822		4,993		3,593		(5,631	)		(4,552	)		(3,244	)		1,191		441		349

Operating Cash Flow	$	29	$	78	$	55	$	(11	)	$	(45	)	$	(33	)	$	18	$	33	$	22

CAPITAL EXPENDITURES


For the years ended December 31	2014		2013		2012

Canadian Operations	$	1,226	$	1,365	$	1,567
USA Operations		1,285		1,283		1,727
Market Optimization		—		3		7
Corporate & Other		15		61		175

	$	2,526	$	2,712	$	3,476

GOODWILL, PROPERTY, PLANT AND EQUIPMENT AND TOTAL ASSETS BY SEGMENT


	Goodwill				Property, Plant and Equipment				Total Assets
As at December 31	2014		2013		2014		2013		2014		2013

Canadian Operations	$	788	$	1,171	$	2,338	$	2,728	$	3,632	$	4,452
USA Operations		2,129		473		13,817		5,127		16,800		6,350
Market Optimization		—		—		1		91		181		161
Corporate & Other		—		—		1,859		2,089		4,008		6,685

	$	2,917	$	1,644	$	18,015	$	10,035	$	24,621	$	17,648

GOODWILL, PROPERTY, PLANT AND EQUIPMENT AND TOTAL ASSETS BY GEOGRAPHIC REGION


	Goodwill				Property, Plant and Equipment				Total Assets
As at December 31	2014		2013		2014		2013		2014		2013

Canada	$	788	$	1,171	$	4,070	$	4,772	$	7,336	$	10,434
United States		2,129		473		13,945		5,263		17,273		6,996
Other Countries		—		—		—		—		12		218

	$	2,917	$	1,644	$	18,015	$	10,035	$	24,621	$	17,648

EXPORT SALES

Sales of natural gas and liquids produced or purchased in Canada delivered to customers outside of Canada were $338 million (2013 – $243 million; 2012 – $177 million).

MAJOR CUSTOMERS

In connection with the marketing and sale of Encana’s own and purchased natural gas and liquids for the year ended December 31, 2014, the Company had one customer which individually accounted for more than 10 percent of Encana’s consolidated revenues, net of royalties. Sales to this customer, which has an investment grade credit rating, were approximately $1,043 million which comprised $634 million in Canada and $409 million in the United States (2013 – one customer with sales of approximately $815 million; 2012 – two customers with sales of approximately $661 million and $534 million).

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3. BUSINESS COMBINATIONS

ATHLON ENERGY INC. ACQUISITION

On November 13, 2014, Encana completed the acquisition of all of the issued and outstanding shares of common stock of Athlon Energy Inc. (“Athlon”) for $5.93 billion, or $58.50 per share. In addition, Encana assumed Athlon’s $1.15 billion senior notes and repaid and terminated Athlon’s credit facility with indebtedness outstanding of $335 million. Encana funded the acquisition of Athlon with cash on hand. Transaction costs of approximately $31 million are included in other expenses. Following completion of the acquisition, Athlon’s $1.15 billion senior notes were redeemed in accordance with the provisions of the governing indentures (See Note 13). Athlon’s operations focused on the acquisition and development of oil and gas properties located in the Permian Basin in Texas.

The transaction was accounted for under the acquisition method, which requires that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The preliminary purchase price allocation, representing consideration paid and the fair values of the assets acquired and liabilities assumed as of the acquisition date, is shown in the table below.


Preliminary Purchase Price Allocation

Assets Acquired:
Cash	$	2
Accounts receivable and other current assets		133
Risk management		80
Proved properties		2,124
Unproved properties		5,338
Other property, plant and equipment		2
Other assets		2
Goodwill		1,724
Liabilities Assumed:
Accounts payable and accrued liabilities		(195	)
Long-term debt, including revolving credit facility		(1,497	)
Asset retirement obligation		(25	)
Deferred income taxes		(1,724	)

Total Purchase Price ⁽¹⁾	$	5,964

(1)

The purchase price includes cash consideration paid for issued and outstanding shares of common stock of Athlon of $58.50 per share totaling $5.93 billion, as well as payments to terminate certain employment agreements with Athlon’s management and payments for certain other existing obligations of Athlon.

The Company used the income approach valuation technique for the fair value of assets acquired and liabilities assumed. The carrying amounts of cash, accounts receivable and other current assets, and accounts payable and accrued liabilities approximate their fair values due to the short-term maturity of the instruments. The fair values of the risk management assets and long-term debt, including the revolving credit facility, are categorized within Level 2 of the fair value hierarchy and were determined using quoted prices and rates from an available pricing source. The fair values of the proved and unproved properties, other property, plant and equipment, other assets, goodwill, and asset retirement obligation are categorized within Level 3 and were determined using relevant market assumptions, including discount rates, future commodity prices and costs, timing of development activities, projections of oil and gas reserves, and estimates to abandon and reclaim producing wells.

Goodwill arose primarily from the requirement to recognize deferred taxes on the difference between the fair value of the assets acquired and liabilities assumed and the respective carry-over tax basis. Goodwill is not amortized and is not deductible for tax purposes.

The results of operations attributable to the Athlon acquisition are included in the Company’s Consolidated Statement of Earnings beginning November 13, 2014. The assets acquired generated revenues of $176 million and a net loss of $3 million for the period from November 13, 2014 to December 31, 2014.

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EAGLE FORD ACQUISITION

On June 20, 2014, Encana completed the acquisition of approximately 45,500 net acres located in the Eagle Ford shale formation from Freeport-McMoRan Oil & Gas LLC and PXP Producing Company LLC for approximately $2.9 billion, after closing adjustments. The acquisition included an interest in certain producing properties and undeveloped lands in the Karnes, Wilson and Atascosa counties of south Texas. Encana funded the acquisition with cash on hand. Transaction costs of approximately $9 million are included in other expenses.

The transaction was accounted for under the acquisition method. The final purchase price allocation, representing consideration paid and the fair values of the assets acquired and liabilities assumed as of the acquisition date, is shown in the table below. Based on the allocation of the consideration paid, no goodwill was recognized.


Final Purchase Price Allocation

Assets Acquired:
Inventory	$	4
Proved properties		2,873
Unproved properties		78
Liabilities Assumed:
Asset retirement obligation		(32	)

Total Purchase Price	$	2,923

The Company used the income approach valuation technique. The fair values of the assets acquired and liabilities assumed are categorized within Level 3 of the fair value hierarchy. The fair values of the assets acquired and liabilities assumed were determined using relevant market assumptions, including future commodity prices and costs, timing of development activities, projections of oil and gas reserves, and estimates to abandon and reclaim producing wells.

The results of operations attributable to the Eagle Ford assets are included in the Company’s Consolidated Statement of Earnings beginning June 20, 2014. The assets acquired generated revenues of $585 million and net earnings of $222 million for the period from June 20, 2014 to December 31, 2014.

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma financial information has been prepared assuming the Athlon and Eagle Ford acquisitions occurred on January 1, 2013. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combinations had been completed at the dates indicated. In addition, the pro forma information does not project Encana’s results of operations for any future period.


	Athlon				Eagle Ford
For the years ended December 31 ($ millions, except per share amounts)	2014		2013		2014		2013

Revenues, Net of Royalties	$	8,572	$	6,139	$	8,760	$	7,189
Net Earnings Attributable to Common Shareholders	$	3,486	$	158	$	3,641	$	741

Net Earnings per Common Share
Basic & Diluted	$	4.71	$	0.21	$	4.91	$	1.01

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4. ACQUISITIONS AND DIVESTITURES


For the years ended December 31	2014			2013			2012

Acquisitions
Canadian Operations	$	21		$	28		$	139
USA Operations		2,995			156			240

Total Acquisitions		3,016			184			379


Divestitures
Canadian Operations		(1,847	)		(685	)		(3,770	)
USA Operations		(2,264	)		(18	)		(271	)
Market Optimization		(205	)		—			—
Corporate & Other		(29	)		(2	)		(2	)

Total Divestitures		(4,345	)		(705	)		(4,043	)

Net Acquisitions & (Divestitures)	$	(1,329	)	$	(521	)	$	(3,664	)

ACQUISITIONS

For the year ended December 31, 2014, acquisitions totaled $3,016 million (2013 – $184 million; 2012 – $379 million), which primarily included the purchase of certain properties in the Eagle Ford shale formation in south Texas as described in Note 3.

DIVESTITURES

For the year ended December 31, 2014, amounts received on the sale of assets were $4,345 million (2013 – $705 million; 2012 – $4,043 million). In 2014, divestitures were $1,847 million in the Canadian Operations and $2,264 million in the USA Operations.

Amounts received from the 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 the respective country cost centre. For divestitures that result in a gain or loss and constitute a business, goodwill is allocated to the divestiture.

The Canadian Operations and USA Operations divestitures included the following transactions:

CANADIAN OPERATIONS

In 2014, divestitures in the Canadian Operations primarily included the sale of the Company’s Bighorn assets in west central Alberta for approximately $1,725 million. For the year ended December 31, 2014, Encana recognized a gain of approximately $1,014 million, before tax, on the sale of the Company’s Bighorn assets in the Canadian cost centre and allocated goodwill of $257 million.

In 2013, divestitures in the Canadian Operations included the sale of the Company’s Jean Marie natural gas assets in northeast British Columbia and other assets.

In 2012, Encana entered into a partnership agreement with a Mitsubishi Corporation subsidiary (“Mitsubishi”) to jointly develop certain lands in northeast British Columbia. Under the agreement, Encana owns 60 percent and Mitsubishi owns 40 percent of the partnership. Mitsubishi agreed to invest approximately C$2.9 billion for its partnership interest, with C$1.45 billion received in February 2012. Mitsubishi agreed to invest the remaining amount of approximately C$1.45 billion, in addition to its 40 percent of the partnership’s future capital investment, based on the expected five year development plan, thereby reducing Encana’s capital funding commitment to 30 percent of the total expected capital investment.

In 2012, the Company entered into an agreement with a PetroChina Company Limited subsidiary (“PetroChina”) to jointly explore and develop certain liquids rich natural gas Duvernay lands in Alberta. PetroChina agreed to invest approximately C$2.18 billion for a 49.9 percent working interest in the lands. PetroChina invested C$1.18 billion in December 2012 and agreed to further invest approximately C$1.0 billion, which will be used to fund half of Encana’s capital funding commitment over an expected commitment period which expires in 2020.

In 2012, Encana entered into an agreement with a Toyota Tsusho Corporation subsidiary (“Toyota Tsusho”) under which Toyota Tsusho agreed to invest approximately C$600 million to acquire a 32.5 percent gross overriding royalty interest in natural gas production from a portion of Encana’s Clearwater play. Toyota Tsusho invested C$100 million in April 2012 and agreed to further invest approximately C$500 million over an expected commitment period of approximately seven years, which runs through to 2019.

In 2012, the Company also closed the sale of two natural gas processing plants in British Columbia and Alberta for proceeds of approximately C$920 million.

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USA OPERATIONS

In 2014, divestitures in the USA Operations primarily included the sale of the Jonah properties for proceeds of approximately $1,636 million and the sale of certain properties in East Texas for proceeds of approximately $495 million. For the year ended December 31, 2014, Encana recognized a gain of approximately $209 million, before tax, on the sale of the Jonah properties in the U.S. cost centre and allocated goodwill of $68 million.

OTHER CAPITAL TRANSACTIONS

The following transactions involve the acquisition or disposition of common shares and, therefore, are excluded from the acquisitions and divestitures table above.

ACQUISITION OF ATHLON

On November 13, 2014, Encana acquired all of the issued and outstanding shares of common stock of Athlon for $5.93 billion, or $58.50 per share. See Note 3 for further details regarding the Athlon transaction.

DIVESTITURE OF INVESTMENT IN PRAIRIESKY

On September 26, 2014, Encana completed the secondary offering of 70.2 million common shares of PrairieSky at a price of C$36.50 per common share for aggregate gross proceeds of approximately C$2.6 billion. As the sale of the investment in PrairieSky resulted in a significant alteration between capitalized costs and proved reserves in the Canadian cost centre, Encana recognized a gain on divestiture of approximately $2.1 billion, before tax.

See Note 18 for further details regarding the PrairieSky transactions.

5. INTEREST


For the years ended December 31	2014		2013		2012

Interest Expense on:
Debt	$	509	$	460	$	474
The Bow office building		75		76		16
Capital leases		37		9		2
Other		33		18		30

	$	654	$	563	$	522

Interest on Debt for the year ended December 31, 2014 includes a one-time outlay of approximately $125 million associated with the early redemption of senior notes assumed in conjunction with the Athlon acquisition (See Note 13).

Interest on Capital leases and Other were previously reported together in 2013 and 2012.

6. FOREIGN EXCHANGE (GAIN) LOSS, NET


For the years ended December 31	2014			2013			2012

Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar debt issued from Canada	$	456		$	349		$	(131	)
Translation of U.S. dollar risk management contracts issued from Canada		(16	)		(19	)		19

		440			330			(112	)

Foreign Exchange on Intercompany Transactions		28			—			4
Other Monetary Revaluations and Settlements		(65	)		(5	)		1

	$	403		$	325		$	(107	)

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7. INCOME TAXES

The provision for income taxes is as follows:


For the years ended December 31	2014			2013			2012

Current Tax
Canada	$	249		$	(152	)	$	(219	)
United States		(21	)		(64	)		(25	)
Other Countries		15			25			44

Total Current Tax Expense (Recovery)		243			(191	)		(200	)


Deferred Tax
Canada		713			(106	)		(902	)
United States		246			52			(935	)
Other Countries		1			(3	)		—

Total Deferred Tax Expense (Recovery)		960			(57	)		(1,837	)

Income Tax Expense (Recovery)	$	1,203		$	(248	)	$	(2,037	)

The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes:


For the years ended December 31	2014			2013			2012

Net Earnings (Loss) Before Income Tax
Canada	$	3,744		$	(316	)	$	(2,246	)
United States		665			46			(2,978	)
Other Countries		220			258			393

Total Net Earnings (Loss) Before Income Tax		4,629			(12	)		(4,831	)
Canadian Statutory Rate		25.7	%		25.1	%		25.0	%

Expected Income Tax		1,190			(3	)		(1,208	)
Effect on Taxes Resulting From:
Statutory rate and other foreign differences		7			(42	)		(412	)
Effect of legislative changes		—			(70	)		—
Non-taxable capital (gains) losses		64			48			(16	)
Tax differences on divestitures and transactions		8			(28	)		(307	)
Partnership tax allocations in excess of funding		(53	)		(41	)		(40	)
Amounts in respect of prior periods		(19	)		(103	)		(64	)
Other		6			(9	)		10

	$	1,203		$	(248	)	$	(2,037	)

Effective Tax Rate		26.0	%		2,066.7	%		42.2	%

Statutory rate and other foreign differences above include statutory and other rate differences and international financing, which were previously reported separately in 2012.

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The net deferred income tax asset (liability) consists of:


As at December 31	2014			2013

Deferred Income Tax Assets
Property, plant and equipment	$	217		$	786
Compensation plans		91			109
Accrued and unpaid expense		59			61
Non-capital and net capital losses carried forward		492			429
Alternative minimum tax and foreign tax credits		205			199
Less valuation allowance		(12	)		(6	)
Other		72			95

Deferred Income Tax Liabilities
Property, plant and equipment		(2,485	)		(407	)
Risk management		(226	)		(63	)
Unrealized foreign exchange gains		(48	)		(120	)
Other		(26	)		(29	)

Net Deferred Income Tax Asset (Liability)	$	(1,661	)	$	1,054

The net deferred income tax asset (liability) is reflected in the Consolidated Balance Sheet as follows:


As at December 31	2014			2013

Current deferred income tax asset	$	—		$	118
Non-current deferred income tax asset		296			939
Current deferred income tax liability		(128	)		(3	)
Non-current deferred income tax liability		(1,829	)		—

Net Deferred Income Tax Asset (Liability)	$	(1,661	)	$	1,054

Tax pools, loss carryforwards, charitable donations and tax credits that can be utilized in future years are as follows:


As at December 31	2014		Expiration Date

Canada
Tax pools	$	2,188	Indefinite
Net capital losses		1	Indefinite
Non-capital losses		58	2027 - 2034

United States
Tax basis	$	6,769	Indefinite
Non-capital losses		1,306	2031 - 2034
Charitable donations		9	2018 - 2019
Alternative minimum tax credits		34	Indefinite
Foreign tax credits (net of valuation allowance)		159	2021 - 2024

As at December 31, 2014, approximately $2.6 billion of Encana’s unremitted earnings from its foreign subsidiaries were considered to be permanently reinvested outside of Canada and, accordingly, Encana has not recognized a deferred tax liability for Canadian income taxes in respect of such earnings. If such earnings were to be remitted to Canada, Encana may be subject to Canadian income taxes and foreign withholding taxes. However, determination of any potential amount of unrecognized deferred income tax liabilities is not practicable.

The following table presents changes in the balance of Encana’s unrecognized tax benefits excluding interest:

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For the years ended December 31	2014			2013

Balance, Beginning of Year	$	(119	)	$	(164	)
Additions for tax positions taken in the current year		(289	)		—
Additions for tax positions of prior years		(1	)		—
Reductions for tax positions of prior years		2			2
Lapse of statute of limitations		—			4
Settlements		2			29
Foreign currency translation		23			10

Balance, End of Year	$	(382	)	$	(119	)

The unrecognized tax benefit is reflected in the Consolidated Balance Sheet as follows:


For the years ended December 31	2014			2013

Income tax receivable	$	(36	)	$	—
Other liabilities and provisions (See Note 14)		(279	)		(133	)
Current deferred income tax liability		1			(2	)
Non-current deferred income tax asset		(68	)		16

Balance, End of Year	$	(382	)	$	(119	)

If recognized, all of Encana’s unrecognized tax benefits as at December 31, 2014 would affect Encana’s effective income tax rate. Encana does not anticipate that the amount of unrecognized tax benefits will significantly change during the next 12 months.

Encana recognizes interest accrued in respect of unrecognized tax benefits in interest expense. During 2014, Encana recognized an expense of $1 million (2013 – recovery of $6 million; 2012 – recovery of $8 million) in interest expense. As at December 31, 2014, Encana had a liability of $2 million (2013 – $1 million) for interest accrued in respect of unrecognized tax benefits.

Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by the taxation authorities.


Jurisdiction		Taxation Year

Canada - Federal		2006 - 2014
Canada - Provincial		2006 - 2014
United States - Federal		2011 - 2014
United States - State		2010 - 2014
Other		2013 - 2014

Encana and its subsidiaries file income tax returns primarily in Canada and the United States. Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion.

8. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES


As at December 31	2014			2013

Trade Receivables and Accrued Revenue	$	1,223		$	864
Prepaids		60			53
Deposits and Other		30			77

		1,313			994
Allowance for Doubtful Accounts		(6	)		(6	)

	$	1,307		$	988

Trade receivables are non-interest bearing. In determining the recoverability of trade receivables, the Company considers the age of the outstanding receivable and the credit worthiness of the counterparties. See Note 23 for further information about credit risk.

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9. PROPERTY, PLANT AND EQUIPMENT, NET


As at December 31	2014							2013
	Cost		Accumulated DD&A ⁽¹⁾			Net		Cost		Accumulated DD&A ⁽¹⁾			Net

Canadian Operations
Proved properties	$	18,271	$	(16,566	)	$	1,705	$	25,003	$	(23,012	)	$	1,991
Unproved properties		478		—			478		598		—			598
Other		155		—			155		139		—			139

		18,904		(16,566	)		2,338		25,740		(23,012	)		2,728

USA Operations
Proved properties		24,279		(16,260	)		8,019		26,529		(22,074	)		4,455
Unproved properties		5,655		—			5,655		470		—			470
Other		143		—			143		202		—			202

		30,077		(16,260	)		13,817		27,201		(22,074	)		5,127

Market Optimization		8		(7	)		1		223		(132	)		91
Corporate & Other		2,470		(611	)		1,859		2,655		(566	)		2,089

	$	51,459	$	(33,444	)	$	18,015	$	55,819	$	(45,784	)	$	10,035

(1)	Depreciation, depletion and amortization.

Canadian Operations and USA Operations property, plant and equipment include internal costs directly related to exploration, development and construction activities of $306 million which have been capitalized during the year ended December 31, 2014 (2013 – $372 million). Included in Corporate and Other are $65 million (2013 – $71 million) of international property costs, which have been fully impaired.

For the year ended December 31, 2014, the Company recognized a ceiling test impairment of nil (2013 – nil; 2012 – $1,822 million) in the Canadian cost centre and nil (2013 – nil; 2012 – $2,842 million) in the U.S. cost centre. The impairments in 2012 resulted primarily from the decline in the 12-month average trailing natural gas prices which reduced proved reserves volumes and values.

The 12-month average trailing prices used in the ceiling test calculations reflect benchmark prices adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality. The benchmark prices are disclosed in Note 26.

CAPITAL LEASE ARRANGEMENTS

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

In December 2013, Encana commenced commercial operations at its Deep Panuke facility located offshore Nova Scotia following successful completion of the Production Field Centre (“PFC”) and issuance of the Production Acceptance Notice. As at December 31, 2014, Canadian Operations property, plant and equipment and total assets include the PFC, which is under a capital lease totaling $520 million (2013 – $536 million).

As at December 31, 2014, the total carrying value of assets under capital lease was $547 million (2013 – $683 million). Liabilities for the capital lease arrangements are included in other liabilities and provisions in the Consolidated Balance Sheet and are disclosed in Note 14.

OTHER ARRANGEMENT

As at December 31, 2014, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,431 million (2013 – $1,587 million) related to The Bow office building, which is under a 25-year lease agreement. The Bow asset is being depreciated over the 60-year estimated life of the building. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized as disclosed in Note 14.

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10. OTHER ASSETS


As at December 31	2014		2013

Deferred Charges and Debt Transaction Costs	$	48	$	58
Long-Term Receivables		70		184
Long-Term Investments and Other		276		284

	$	394	$	526

11. GOODWILL


As at December 31	2014		2013

Canada	$	788	$	1,171
United States		2,129		473

	$	2,917	$	1,644

During 2014, the Company recognized goodwill of $1,724 million in conjunction with the Athlon acquisition in the United States as described in Note 3. In Canada, the Company allocated goodwill of $257 million to the Bighorn divestiture and derecognized $39 million upon the divestiture of Encana’s investment in PrairieSky as described in Notes 4 and 18. In the United States, the Company allocated goodwill of $68 million to the Jonah divestiture as described in Note 4.

There were no additions or dispositions of goodwill during 2013 and the Company has not recognized any previous goodwill impairments. The change in the Canada goodwill balance also reflects the movements due to foreign currency translation.

Goodwill was assessed for impairment as at December 31, 2014 and December 31, 2013. The fair values of the Canada and United States reporting units were determined to be greater than the respective carrying values of the reporting units. Accordingly, no goodwill impairments were recognized.

12. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES


As at December 31	2014		2013

Trade Payables	$	428	$	265
Capital Accruals		729		398
Royalty and Production Accruals		495		473
Other Accruals		385		514
Interest Payable		100		111
Outstanding Disbursements		4		2
Current Portion of Capital Lease Obligations (See Note 14)		59		66
Current Portion of Asset Retirement Obligation (See Note 15)		43		66

	$	2,243	$	1,895

Payables and accruals are non-interest bearing. Interest payable represents amounts accrued related to Encana’s unsecured notes as disclosed in Note 13.

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13. LONG-TERM DEBT


As at December 31	Note		C$ Principal Amount		2014			2013

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings		A	$	—	$	—		$	—
Canadian Unsecured Notes:		B
5.80% due January 18, 2018				750		647			705

			$	750		647			705


U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings		A				1,277			—
U.S. Unsecured Notes:		B
5.80% due May 1, 2014						—			1,000
5.90% due December 1, 2017						700			700
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						500			500
6.50% due February 1, 2038						800			800
5.15% due November 15, 2041						400			400

						6,677			6,400

Total Principal		F				7,324			7,105

Increase in Value of Debt Acquired		C				34			40
Debt Discounts		D				(18	)		(21	)
Current Portion of Long-Term Debt		E				—			(1,000	)

					$	7,340		$	6,124

Annual Report 2014 | Encana Corporation 73

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A) REVOLVING CREDIT AND TERM LOAN BORROWINGS

CANADIAN REVOLVING CREDIT AND TERM LOAN BORROWINGS

At December 31, 2014, Encana had in place a committed revolving bank credit facility for C$3.5 billion ($3.0 billion), of which $1.7 billion remains unused. The facility, which matures in June 2018, is fully revolving up to maturity. The facility is extendible from time to time, but not more than once per year, for a period not longer than five years plus 90 days from the date of the extension request, at the option of the lenders and upon notice from Encana. The facility is unsecured and bears interest at the lenders’ rates for Canadian prime, U.S. base rate, Bankers’ Acceptances or LIBOR, plus applicable margins.

During 2014, the Company borrowed on its revolving credit facilities. Borrowings include LIBOR loans of $1,277 million maturing at various dates with a weighted average interest rate of 1.62 percent. These amounts are fully supported and Management expects that they will continue to be supported by revolving credit facilities that have no repayment requirements within the next year and which expire in 2018. There were no outstanding balances related to the Company’s commercial paper or revolving credit facilities as at December 31, 2013.

U.S. REVOLVING CREDIT AND TERM LOAN BORROWINGS

At December 31, 2014, one of Encana’s subsidiaries had in place a committed revolving bank credit facility for $1.0 billion, all of which remained unused. The facility, which matures in June 2018, is guaranteed by Encana Corporation and is fully revolving up to maturity. The facility is extendible from time to time, but not more than once per year, for a period not longer than five years plus 90 days from the date of the extension request, at the option of the lenders and upon notice from the subsidiary. This facility bears interest at either the lenders’ U.S. base rate or LIBOR, plus applicable margins.

Standby fees paid in 2014 relating to Canadian and U.S. revolving credit and term loan agreements were approximately $12 million (2013 – $14 million; 2012 – $15 million).

Encana is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants as at December 31, 2014.

B) UNSECURED NOTES

SHELF PROSPECTUS

Encana has in place a shelf prospectus, whereby the Company may issue from time to time up to $6.0 billion, or the equivalent in foreign currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants and units in Canada and/or the U.S. The shelf prospectus was filed in June 2014 and expires in July 2016. At December 31, 2014, the $6.0 billion shelf prospectus remained accessible, the availability of which is dependent upon market conditions. This shelf prospectus replaced a $4.0 billion debt shelf prospectus for U.S. unsecured notes which expired in June 2014.

Unsecured notes include medium-term notes and senior notes that are issued from time to time under trust indentures and have equal priority with respect to the payment of both principal and interest.

U.S. UNSECURED NOTES

On March 28, 2014, the tender offer and consent solicitation expired and on March 31, 2014, Encana paid the consenting note holders an aggregate of approximately $792 million in cash reflecting a $768 million principal debt repayment, $2 million for the consent payment and $22 million of accrued and unpaid interest.

On December 16, 2014, Encana completed the redemption of the $500 million 7.375 percent senior notes due April 15, 2021 and the $650 million 6.00 percent senior notes due May 1, 2022, which were assumed by Encana in conjunction with the Athlon acquisition as discussed in Note 3. The Company recognized a one-time outlay of approximately $125 million as a result of the early redemption. Encana used proceeds from the Company’s revolving credit facility of $1,277 million to redeem the senior notes.

C) INCREASE IN VALUE OF DEBT ACQUIRED

Certain of the notes and debentures of the Company were acquired in business combinations and were accounted for at their fair value at the dates of acquisition. The difference between the fair value and the principal amount of the debt is being amortized over the remaining life of the outstanding debt acquired, which is approximately 16 years.

In conjunction with the Athlon acquisition, the Company recorded an increase in the fair value of the debt acquired of approximately $12 million, which was expensed upon redemption of the senior notes and is included in other expenses in the Company’s Consolidated Statement of Earnings.

74 Encana Corporation | Annual Report 2014

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D) DEBT DISCOUNTS

Long-term debt premiums and discounts are capitalized within long-term debt and are being amortized using the effective interest method. During 2014 and 2013, no debt discounts were capitalized.

E) CURRENT PORTION OF LONG-TERM DEBT


As at December 31	C$ Principal Amount		2014		2013

5.80% due May 1, 2014	$	—	$	—	$	1,000

	$	—	$	—	$	1,000

F) MANDATORY DEBT PAYMENTS


As at December 31	C$ Principal Amount		US$ Principal Amount		Total US$ Equivalent

2015	$	—	$	—	$	—
2016		—		—		—
2017		—		700		700
2018		750		1,277		1,924
2019		—		500		500
Thereafter		—		4,200		4,200

Total	$	750	$	6,677	$	7,324

The amount due in 2015 excludes LIBOR loans, which are fully supported by revolving credit facilities that have no repayment requirements within the next year. The revolving credit facilities are fully revolving for a period of up to five years. Based on the current maturity dates of the credit facilities, the payments are included in 2018.

Long-term debt is accounted for at amortized cost using the effective interest method of amortization. As at December 31, 2014, total long-term debt had a carrying value of $7,340 million and a fair value of $7,788 million (2013 – carrying value of $7,124 million and a fair value of $7,805 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, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.

14. OTHER LIABILITIES AND PROVISIONS


As at December 31	2014		2013

The Bow Office Building (See Note 9)	$	1,486	$	1,631
Capital Lease Obligations (See Note 9)		473		544
Unrecognized Tax Benefits (See Note 7)		279		133
Pensions and Other Post-Employment Benefits (See Note 21)		144		110
Long-Term Incentives (See Note 20)		70		58
Other		32		44

	$	2,484	$	2,520

Long-Term Incentives was previously reported in Other in 2013.

Annual Report 2014 | Encana Corporation 75

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THE BOW OFFICE BUILDING

As described in Note 9, Encana has recognized the accumulated costs for The Bow office building, which is under a 25-year lease agreement. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized. Encana has also subleased part of The Bow office space to a subsidiary of Cenovus. The total undiscounted future payments related to the lease agreement and the total undiscounted future amounts expected to be recovered from the Cenovus sublease are outlined below.


(undiscounted)	2015			2016			2017			2018			2019			Thereafter			Total
Expected Future Lease Payments	$	80		$	81		$	82		$	82		$	83		$	1,652		$	2,060

Sublease Recoveries	$	(39	)	$	(40	)	$	(40	)	$	(40	)	$	(41	)	$	(812	)	$	(1,012	)

CAPITAL LEASE OBLIGATIONS

As described in Note 9, the Company has several lease arrangements that are accounted for as capital leases, including an office building, equipment and an offshore production platform.

The PFC commenced commercial operations in December 2013. Accordingly, Encana derecognized the asset under construction and related liability and recorded the PFC as a capital lease asset with a corresponding capital lease obligation. Under the lease contract, Encana has a purchase option and the option to extend the lease for 12 one-year terms at fixed prices after the initial lease term expires in 2021. As a result, the lease contract qualifies as a variable interest and 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 lease entity and its affiliates, other than the contractual payments under the lease and operating contracts.

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


	2015		2016		2017		2018		2019		Thereafter		Total

Expected Future Lease Payments	$	98	$	98	$	99	$	99	$	99	$	232	$	725
Less Amounts Representing Interest		39		36		32		27		23		36		193

Present Value of Expected Future Lease Payments	$	59	$	62	$	67	$	72	$	76	$	196	$	532

15. ASSET RETIREMENT OBLIGATION


As at December 31	2014			2013

Asset Retirement Obligation, Beginning of Year	$	966		$	969
Liabilities Incurred and Acquired (See Note 3)		85			38
Liabilities Settled and Divested		(188	)		(126	)
Change in Estimated Future Cash Outflows		35			68
Accretion Expense		52			53
Foreign Currency Translation		(37	)		(36	)

Asset Retirement Obligation, End of Year	$	913		$	966


Current Portion (See Note 12)	$	43		$	66
Long-Term Portion		870			900

	$	913		$	966

76 Encana Corporation | Annual Report 2014

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16. SHARE CAPITAL

AUTHORIZED

The Company is authorized to issue an unlimited number of no par value common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares.

ISSUED AND OUTSTANDING


As at December 31	2014				2013
	Number (millions)		Amount		Number (millions)			Amount

Common Shares Outstanding, Beginning of Year		740.9	$	2,445		736.3		$	2,354
Common Shares Cancelled		—		—		(0.8	)		(2	)
Common Shares Issued under Dividend Reinvestment Plan		0.3		5		5.4			93

Common Shares Outstanding, End of Year		741.2	$	2,450		740.9		$	2,445

During the year ended December 31, 2014, Encana issued 240,839 common shares totaling $5 million under the Company’s dividend reinvestment plan (2013 – issued 5,385,845 common shares totaling $93 million).

During the year ended December 31, 2013, Encana cancelled 767,327 common shares reserved for issuance to shareholders upon exchange of predecessor companies’ shares. In accordance with the terms of the merger agreement which formed Encana, shares which remained unexchanged were extinguished. Accordingly, the weighted average book value of the common shares extinguished of $2 million was transferred to paid in surplus.

DIVIDENDS

For the year ended December 31, 2014, Encana paid dividends of $0.28 per common share totaling $207 million (2013 – $0.67 per common share totaling $494 million; 2012 – $0.80 per common share totaling $588 million). The Company’s quarterly dividend payment in 2014 was $0.07 per common share. The quarterly dividend payment in 2013 was $0.20 per common share for the first three quarters and $0.07 per common share for the fourth quarter. The quarterly dividend payment in 2012 was $0.20 per common share.

For the year ended December 31, 2014, the dividends paid included $5 million in common shares as disclosed above, which were issued in lieu of cash dividends under the Company’s dividend reinvestment plan (2013 – $93 million; 2012 – nil).

On February 25, 2015, the Board declared a dividend of $0.07 per common share payable on March 31, 2015 to common shareholders of record as of March 13, 2015.

EARNINGS PER COMMON SHARE

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


For the years ended December 31 (millions, except per share amounts)	2014		2013		2012

Net Earnings (Loss) Attributable to Common Shareholders	$	3,392	$	236	$	(2,794	)

Number of Common Shares:
Weighted average common shares outstanding – Basic		741.0		737.7		736.3
Effect of dilutive securities		—		—		—

Weighted average common shares outstanding – Diluted		741.0		737.7		736.3


Net Earnings (Loss) per Common Share
Basic	$	4.58	$	0.32	$	(3.79	)
Diluted	$	4.58	$	0.32	$	(3.79	)

Annual Report 2014 | Encana Corporation 77

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ENCANA STOCK OPTION PLAN

Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the market value of the common shares on the date the options are granted. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire five years after the date granted.

All options outstanding as at December 31, 2014 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. The Performance TSARs vest and expire under the same terms and conditions as the underlying option. 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, Encana does not consider outstanding TSARs to be potentially dilutive securities. See Note 20 for further information on Encana’s outstanding and exercisable TSARs and Performance TSARs.

At December 31, 2014, there were 27.3 million common shares reserved for issuance under stock option plans (2013 – 19.1 million; 2012 – 18.8 million).

ENCANA RESTRICTED SHARE UNITS (“RSUs”)

Encana has a share-based compensation plan whereby eligible employees are granted RSUs. An RSU is a conditional grant to receive an Encana common share, or the cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The value of one RSU is notionally equivalent to one Encana common share. RSUs vest three years from the date granted, provided the employee remains actively employed with Encana on the vesting date. The Company intends to settle vested RSUs in cash on the vesting date. As a result, Encana does not consider RSUs to be potentially dilutive securities. See Note 20 for further information on Encana’s outstanding RSUs.

ENCANA SHARE UNITS PREVIOUSLY HELD BY CENOVUS EMPLOYEES

On November 30, 2009, Encana completed a corporate reorganization to split into two independent publicly traded energy companies – Encana Corporation and Cenovus Energy Inc. (the “Split Transaction”). In conjunction with the Split Transaction, each holder of Encana share units disposed of their right in exchange for the grant of new Encana share units and Cenovus share units. Share units included TSARs, Performance TSARs, SARs and Performance SARs. The terms and conditions of the share units were similar to the terms and conditions of the original share units. There was no impact on Encana’s net earnings for the share units held by Cenovus employees. As at December 31, 2014, all remaining share units held by Cenovus employees have expired.

17. ACCUMULATED OTHER COMPREHENSIVE INCOME


For the years ended December 31	2014			2013

Foreign Currency Translation Adjustment
Balance, Beginning of Year	$	693		$	739
Change in Foreign Currency Translation Adjustment		22			(46	)

Balance, End of Year	$	715		$	693


Pension and Other Post-Employment Benefit Plans
Balance, Beginning of Year	$	(9	)	$	(69	)
Net Actuarial Gains and (Losses) and Plan Amendment (See Note 21)		(22	)		65
Income Taxes		7			(17	)
Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 21)		(1	)		11
Income Taxes		—			(3	)
Reclassification of Net Prior Service Costs and (Credits) to Net Earnings (See Note 21)		(1	)		—
Income Taxes		—			—
Settlement and Curtailment in Defined Benefit Plan Expense (See Note 21)		—			6
Income Taxes		—			(2	)

Balance, End of Year	$	(26	)	$	(9	)

Total Accumulated Other Comprehensive Income	$	689		$	684

78 Encana Corporation | Annual Report 2014

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18. NONCONTROLLING INTEREST

INITIAL PUBLIC OFFERING OF COMMON SHARES OF PRAIRIESKY

On May 22, 2014, PrairieSky filed a final prospectus to qualify the distribution of 52.0 million common shares (the “IPO”), to be sold by Encana pursuant to the terms of an underwriting agreement dated May 22, 2014, at a price of C$28.00 per common share (the “Offering Price”).

On May 27, 2014, prior to closing the IPO, PrairieSky acquired from Encana a royalty business in exchange for common shares of PrairieSky pursuant to the Purchase and Sale Agreement dated May 22, 2014 between PrairieSky and Encana (the “Agreement”). The royalty business assets acquired by PrairieSky comprise: (i) fee simple mineral title in lands prospective for petroleum, natural gas and certain other mines and minerals located predominantly in central and southern Alberta (the “Fee Lands”); (ii) lessor interests in and to leases that are currently issued in respect of certain Fee Lands; (iii) royalty interests, including overriding royalty interests, gross overriding royalty interests and production payments on lands located predominantly in Alberta; (iv) an irrevocable, perpetual licence to certain proprietary seismic data of Encana (the “Seismic Licence”); and (v) certain other related assets as set forth in the Agreement.

As part of the Agreement, PrairieSky and Encana entered into: (i) a Seismic Licence Agreement whereby Encana granted the Seismic Licence to PrairieSky; and (ii) Lease Issuance and Administration Agreements whereby PrairieSky issued leases to document Encana’s retention of its working interest in respect of certain Fee Lands and pursuant to which PrairieSky receives royalties from Encana.

On May 29, 2014, Encana completed the IPO of 52.0 million common shares of PrairieSky at the Offering Price for gross proceeds of approximately C$1.46 billion. On June 3, 2014, the over-allotment option granted to the underwriters to purchase up to an additional 7.8 million common shares was exercised in full for gross proceeds of approximately C$218.4 million. Encana received aggregate gross proceeds from the IPO of approximately C$1.67 billion ($1.54 billion). Subsequent to the IPO, Encana owned 70.2 million common shares of PrairieSky, representing a 54 percent ownership interest.

The noncontrolling interest in the former consolidated subsidiary, PrairieSky, was reflected as a separate component of Total Equity in the Consolidated Balance Sheet. Encana recorded $117 million of the proceeds from the IPO as a noncontrolling interest and the remainder of the proceeds of $1,427 million, less transaction costs of $82 million, was recognized as paid in surplus.

SECONDARY PUBLIC OFFERING OF COMMON SHARES OF PRAIRIESKY

On September 8, 2014, Encana and PrairieSky announced the secondary offering of 70.2 million common shares of PrairieSky at a price of C$36.50 per common share, for aggregate gross proceeds to Encana of approximately C$2.6 billion. Following the completion of the secondary offering on September 26, 2014, Encana no longer holds an interest in PrairieSky. As discussed in Note 4, the PrairieSky divestiture resulted in a significant alteration between capitalized costs and proved reserves in the Canadian cost centre. Accordingly, Encana recognized a gain on the divestiture of approximately $2,094 million, which is included in (gain) loss on divestitures in the Company’s Consolidated Statement of Earnings. In conjunction with the divestiture, Encana derecognized the carrying amount of the net assets of $258 million, including goodwill of $39 million, and the noncontrolling interest of $133 million.

DISTRIBUTIONS TO NONCONTROLLING INTEREST OWNERS

During the period from May 29, 2014 to September 25, 2014, PrairieSky paid dividends of C$0.3174 per common share totaling $38 million, of which $18 million is attributable to the noncontrolling interest as presented in the Consolidated Statement of Changes in Shareholders’ Equity and Consolidated Statement of Cash Flows.

NET EARNINGS ATTRIBUTABLE TO NONCONTROLLING INTEREST

During the period from May 29, 2014 to September 25, 2014, the Company held a controlling interest in PrairieSky. Accordingly, Encana consolidated 100 percent of the financial position and results of operations of PrairieSky and recognized a noncontrolling interest for the third party ownership. For the year ended December 31, 2014, net earnings and comprehensive income of $34 million were attributable to the noncontrolling interest as presented in the Consolidated Statement of Earnings and Consolidated Statement of Comprehensive Income.

19. RESTRUCTURING CHARGES

In November 2013, Encana announced its plans to align the organizational structure in support of the Company’s strategy. For the year ended December 31, 2014, Encana has incurred restructuring charges totaling $36 million relating primarily to severance costs, which are included in administrative expense in the Company’s Consolidated Statement of Earnings (2013 – $88 million). Of the $124 million in restructuring charges incurred to date, $4 million remains accrued as at December 31, 2014 (2013 – $65 million). Total restructuring charges are expected to be approximately $133 million before tax. The remaining restructuring charges of approximately $9 million are anticipated to be incurred in 2015.

Annual Report 2014 | Encana Corporation 79

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20. COMPENSATION PLANS

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

Encana accounts for TSARs, Performance TSARs, SARs, Performance SARs, PSUs, and RSUs held by Encana 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. TSARs, Performance TSARs, SARs and Performance SARs granted vest and are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years (with the exception of Performance TSARs granted in 2013) and expire five years after the date granted. PSUs and RSUs vest three years from the date of grant, provided the employee remains actively employed with Encana on the vesting date.

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


As at December 31, 2014	Encana US$ Share Units			Encana C$ Share Units

Risk Free Interest Rate		1.01	%		1.01	%
Dividend Yield		2.02	%		1.91	%
Expected Volatility Rate		30.66	%		29.11	%
Expected Term		1.5 yrs			1.7 yrs
Market Share Price	US$	13.87		C$	16.17


As at December 31, 2013	Encana US$ Share Units			Encana C$ Share Units			Cenovus C$ Share Units

Risk Free Interest Rate		1.09	%		1.09	%		1.09	%
Dividend Yield		1.55	%		1.50	%		3.18	%
Expected Volatility Rate		33.20	%		30.42	%		27.75	%
Expected Term		1.8 yrs			1.7 yrs			0.1 yrs
Market Share Price	US$	18.05		C$	19.18		C$	30.40

For both Encana and Cenovus share units held by Encana employees, volatility was estimated using historical volatility rates.

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


For the years ended December 31	2014			2013			2012

Compensation Costs of Transactions Classified as Cash-Settled	$	25		$	63		$	42
Compensation Costs of Transactions Classified as Equity-Settled ⁽¹⁾		(2	)		3			5

Total Share-Based Compensation Costs		23			66			47
Less: Total Share-Based Compensation Costs Capitalized		(6	)		(22	)		(14	)

Total Share-Based Compensation Expense	$	17		$	44		$	33


Recognized on the Consolidated Statement of Earnings in:
Operating expense	$	12		$	18		$	13
Administrative expense		5			26			20

	$	17		$	44		$	33

(1)	RSUs may be settled in cash or equity as determined by Encana. The Company’s decision to cash settle RSUs was made subsequent to the original grant date.

80 Encana Corporation | Annual Report 2014

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As at December 31, 2014, the liability for share-based payment transactions totaled $99 million (2013 – $169 million), of which $29 million (2013 – $111 million) is recognized in accounts payable and accrued liabilities.


For the years ended December 31	2014		2013		2012

Liability for Cash-Settled Share-Based Payment Transactions:
Unvested	$	78	$	121	$	85
Vested		21		48		71

	$	99	$	169	$	156

The following sections outline certain information related to Encana’s compensation plans as at December 31, 2014.

A) TANDEM STOCK APPRECIATION RIGHTS

All options to purchase common shares issued under the Encana Stock Option Plan have associated 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 exercise over the original grant price. The TSARs vest and expire under the same terms and conditions as the underlying option.

The following tables summarize information related to the Encana TSARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding TSARs			Weighted Average Exercise Price (C$)		Outstanding TSARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		22,512			23.11		17,168			27.84
Granted		5,271			20.57		9,709			18.08
Exercised - SARs		(1,443	)		19.84		(1	)		19.90
Exercised - Options		(1	)		18.06		—			—
Forfeited		(4,656	)		23.16		(2,663	)		26.60
Expired		(1,282	)		29.06		(1,701	)		36.60

Outstanding, End of Year		20,401			22.30		22,512			23.11

Exercisable, End of Year		9,951			25.40		9,360			27.84

As at December 31, 2014

Outstanding Encana TSARs

Exercisable Encana TSARs

Range of Exercise Price (C$)

Number
of TSARs
(thousands
of units)

Weighted
Average
Remaining
Contractual
Life (years)

Weighted
Average
Exercise
Price (C$)

Number
of TSARs
(thousands
of units)

Weighted
Average
Exercise
Price (C$)

10.00 to 19.99

7,108

3.16

18.10

1,853

18.12

20.00 to 29.99

9,057

3.09

21.05

3,862

21.63

30.00 to 39.99

4,236

0.61

32.03

4,236

32.03

20,401

2.60

22.30

9,951

25.40

As at December 31, 2014, there was approximately $5 million of total unrecognized compensation costs (2013 – $29 million) related to unvested TSARs held by Encana employees. The costs are expected to be recognized over a weighted average period of 2.0 years.

Annual Report 2014 | Encana Corporation 81

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The following table summarizes information related to the Cenovus TSARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding TSARs			Weighted Average Exercise Price (C$)		Outstanding TSARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		527			26.29		2,025			29.75
Exercised - SARs		(499	)		26.29		(885	)		28.81
Exercised - Options		(4	)		26.39		(6	)		29.32
Forfeited		—			—		(14	)		31.16
Expired		(24	)		26.38		(593	)		34.21

Outstanding, End of Year		—			—		527			26.29

Exercisable, End of Year		—			—		527			26.29

During the year, Encana recorded a reduction in compensation costs of $15 million related to the Encana TSARs and a reduction in compensation costs of $1 million related to the Cenovus TSARs (2013 – compensation costs of $21 million related to the Encana TSARs and a reduction of compensation costs of $4 million related to the Cenovus TSARs; 2012 – compensation costs of $6 million related to the Encana TSARs and a reduction of compensation costs of $1 million related to Cenovus TSARs).

B) PERFORMANCE TANDEM STOCK APPRECIATION RIGHTS

From 2007 to 2009, Encana granted Performance TSARs. Upon vesting, in lieu of exercising the option, the option holder has the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of exercise over the original grant price. The Performance TSARs vest and expire under the same terms and conditions as the underlying option. Vesting is also subject to Encana attaining prescribed performance relative to an internal recycle ratio and predetermined performance targets. Performance TSARs that do not vest when eligible are forfeited and cancelled.

In 2013, Encana granted Performance TSARs to the President & Chief Executive Officer. The Performance TSARs vest and expire over the same terms and conditions as the underlying option. Under this 2013 grant, vesting is also subject to Encana achieving prescribed performance targets over a four-year period based on Encana’s share price performance. Performance TSARs that do not vest when eligible are forfeited and cancelled.

The following tables summarize information related to the Encana Performance TSARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding Performance TSARs			Weighted Average Exercise Price (C$)		Outstanding Performance TSARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		3,125			25.74		4,879			32.44
Granted		—			—		935			18.00
Forfeited		(61	)		29.04		(453	)		29.12
Expired		(2,129	)		29.04		(2,236	)		36.44

Outstanding, End of Year		935			18.00		3,125			25.74

Exercisable, End of Year		—			—		2,190			29.04

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As at December 31, 2014

Outstanding Encana Performance TSARs

Exercisable Encana
Performance TSARs

Range of Exercise Price (C$)

Number
of TSARs
(thousands
of units)

Weighted
Average
Remaining
Contractual
Life (years)

Weighted
Average
Exercise
Price (C$)

Number
of TSARs
(thousands
of units)

Weighted
Average
Exercise
Price (C$)

10.00 to 19.99

935

3.45

18.00

—

935

3.45

18.00

—

As at December 31, 2014, there was approximately $1 million of total unrecognized compensation costs (2013 – $1 million) related to unvested Performance TSARs held by Encana employees. The costs are expected to be recognized over a weighted average period of 2.3 years.

The following table summarizes information related to the Cenovus Performance TSARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding Performance TSARs			Weighted Average Exercise Price (C$)		Outstanding Performance TSARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		953			26.27		3,205			29.00
Exercised - SARs		(908	)		26.27		(1,466	)		28.72
Exercised - Options		(5	)		26.27		(9	)		29.69
Forfeited		(1	)		26.27		(13	)		26.27
Expired		(39	)		26.27		(764	)		32.96

Outstanding, End of Year		—			—		953			26.27

Exercisable, End of Year		—			—		953			26.27

During the year, Encana recorded compensation costs of $1 million related to the Encana Performance TSARs and a reduction in compensation costs of $1 million related to the Cenovus Performance TSARs (2013 – compensation costs of $1 million related to the Encana Performance TSARs and a reduction of compensation costs of $6 million related to the Cenovus Performance TSARs; 2012 – reduction of compensation costs of $1 million related to the Encana Performance TSARs and reduction of compensation costs of $2 million related to the Cenovus Performance TSARs).

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C) STOCK APPRECIATION RIGHTS

During 2008 and 2009, Canadian dollar denominated SARs were granted to employees, which entitle the employee to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of exercise over the original grant price of the right.

The following tables summarize information related to the Encana SARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding SARs			Weighted Average Exercise Price (C$)		Outstanding SARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		730			29.11		1,843			33.79
Forfeited		(20	)		29.91		(156	)		30.02
Expired		(710	)		29.09		(957	)		37.98

Outstanding, End of Year		—			—		730			29.11

Exercisable, End of Year		—			—		730			29.11

Since 2010, U.S. dollar denominated SARs have been granted to eligible U.S. based employees. The terms and conditions are similar to the Canadian dollar denominated SARs. The following tables summarize information related to U.S. dollar denominated Encana SARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding SARs			Weighted Average Exercise Price (US$)		Outstanding SARs			Weighted Average Exercise Price (US$)

Outstanding, Beginning of Year		14,930			23.79		12,165			26.50
Granted		3,139			19.10		5,048			17.95
Exercised		(1,095	)		19.96		(2	)		17.95
Forfeited		(4,667	)		23.49		(2,281	)		25.30
Expired		(43	)		26.04		—			—

Outstanding, End of Year		12,264			23.04		14,930			23.79

Exercisable, End of Year		7,310			25.97		7,328			27.32

As at December 31, 2014

Outstanding Encana SARs

Exercisable Encana SARs

Range of Exercise Price (US$)

Number
of SARs
(thousands
of units)

Weighted
Average
Remaining
Contractual
Life (years)

Weighted
Average
Exercise
Price (US$)

Number
of SARs
(thousands
of units)

Weighted
Average
Exercise
Price (US$)

10.00 to 19.99

5,110

3.60

18.20

760

17.97

20.00 to 29.99

3,530

2.13

21.75

2,926

21.66

30.00 to 39.99

3,624

0.58

31.13

3,624

31.13

12,264

2.28

23.04

7,310

25.97

As at December 31, 2014, there was approximately $2 million of total unrecognized compensation costs (2013 – $18 million) related to unvested SARs held by Encana employees. The costs are expected to be recognized over a weighted average period of 2.2 years.

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The following table summarizes information related to the Cenovus SARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding SARs			Weighted Average Exercise Price (C$)		Outstanding SARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		230			26.42		1,027			31.25
Exercised		(212	)		26.35		(385	)		28.38
Forfeited		(2	)		29.04		(23	)		33.62
Expired		(16	)		26.95		(389	)		36.82

Outstanding, End of Year		—			—		230			26.42

Exercisable, End of Year		—			—		230			26.42

During the year, Encana recorded a reduction of compensation costs of $2 million related to the Encana SARs and no compensation costs related to the Cenovus SARs (2013 – compensation costs of $1 million related to the Encana SARs and a reduction in compensation costs of $2 million related to the Cenovus SARs; 2012 – compensation costs of $7 million related to the Encana SARs and a reduction in compensation costs of $1 million related to the Cenovus SARs).

D) PERFORMANCE STOCK APPRECIATION RIGHTS

During 2008 and 2009, Encana granted Performance SARs to certain employees, which entitle the employee to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of exercise over the original grant price. Performance SARs are subject to Encana attaining prescribed performance relative to an internal recycle ratio and predetermined key measures. Performance SARs that do not vest when eligible are forfeited.

The following table summarizes information related to the Encana Performance SARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding Performance SARs			Weighted Average Exercise Price (C$)		Outstanding Performance SARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		1,181			29.04		2,455			32.20
Forfeited		(17	)		29.04		(239	)		29.48
Expired		(1,164	)		29.04		(1,035	)		36.44

Outstanding, End of Year		—			—		1,181			29.04

Exercisable, End of Year		—			—		1,181			29.04

The following table summarizes information related to the Cenovus Performance SARs held by Encana employees:


As at December 31	2014					2013
(thousands of units)	Outstanding Performance SARs			Weighted Average Exercise Price (C$)		Outstanding Performance SARs			Weighted Average Exercise Price (C$)

Outstanding, Beginning of Year		385			26.27		1,319			28.74
Exercised		(365	)		26.27		(631	)		28.32
Forfeited		—			—		(9	)		26.47
Expired		(20	)		26.27		(294	)		32.96

Outstanding, End of Year		—			—		385			26.27

Exercisable, End of Year		—			—		385			26.27

During the year, Encana recorded no compensation costs related to the Encana Performance SARs and no compensation costs related to the Cenovus Performance SARs (2013 – no compensation costs related to the Encana Performance SARs and a reduction in compensation costs of $3 million related to the Cenovus Performance SARs; 2012 – no compensation costs related to the Encana Performance SARs and no compensation costs related to the Cenovus Performance SARs).

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E) PERFORMANCE SHARE UNITS

Since 2010, PSUs have been granted to eligible employees, which entitle the employee to receive, upon vesting, a cash payment equal to the value of one common share of Encana for each PSU held, depending upon the terms of the PSU Plan. PSUs vest three years from the date of grant, provided the employee remains actively employed with Encana on the vesting date.

The ultimate value of the PSUs will depend upon Encana’s performance relative to predetermined corresponding performance targets measured over a three-year period. For grants during 2010 through 2012, performance is measured relative to an internal recycle ratio as assessed by the Board on an annual basis to determine whether the performance criteria have been met. Based on this assessment, up to a maximum of two times the original PSU grant may be eligible to vest in respect of the year being measured. The respective proportion of the original PSU grant deemed eligible to vest for each year will be valued and the notional cash value deposited to a PSU account, with payout deferred to the final vesting date. For grants made in 2013, performance is measured over a three-year period relative to a specified performance peer group.

The following tables summarize information related to the PSUs:


(thousands of units)	Canadian Dollar Denominated Outstanding PSUs
As at December 31	2014			2013

Unvested and Outstanding, Beginning of Year		1,134			961
Granted		457			856
Deemed Eligible to Vest		(211	)		(552	)
Units, in Lieu of Dividends		18			40
Forfeited		(176	)		(171	)

Unvested and Outstanding, End of Year		1,222			1,134


(thousands of units)	U.S. Dollar Denominated Outstanding PSUs
As at December 31	2014			2013

Unvested and Outstanding, Beginning of Year		363			693
Granted		167			192
Deemed Eligible to Vest		(173	)		(474	)
Units, in Lieu of Dividends		4			14
Forfeited		(83	)		(62	)

Unvested and Outstanding, End of Year		278			363

As at December 31, 2014, there was approximately $12 million of total unrecognized compensation costs (2013 – $16 million) related to unvested PSUs held by Encana employees. The costs are expected to be recognized over a weighted average period of 1.5 years.

During the year, Encana recorded compensation costs of $4 million related to the outstanding PSUs (2013 – $11 million; 2012 – $12 million).

F) DEFERRED SHARE UNITS

The Company has in place a program whereby Directors and certain key employees are issued DSUs, which vest immediately, are equivalent in value to a common share of the Company and are settled in cash.

Under the DSU Plan, employees have the option to convert either 25 or 50 percent of their annual High Performance Results (“HPR”) award into DSUs. The number of DSUs converted is based on the value of the award divided by the closing value of Encana’s share price at the end of the performance period of the HPR award.

For both Directors and employees, DSUs can only be redeemed following departure from Encana in accordance with the terms of the respective DSU Plan and must be redeemed prior to December 15th of the year following the departure from Encana.

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The following table summarizes information related to the DSUs:


(thousands of units)	Canadian Dollar Denominated Outstanding DSUs
As at December 31	2014			2013

Outstanding, Beginning of Year		1,027			974
Granted		152			106
Converted from HPR awards		—			37
Units, in Lieu of Dividends		14			41
Redeemed		(302	)		(131	)

Outstanding, End of Year		891			1,027

During the year, Encana recorded compensation costs of $1 million related to the outstanding DSUs (2013 – $2 million; 2012 – $2 million).

G) RESTRICTED SHARE UNITS

Since 2011, RSUs have been granted to eligible employees. An RSU is a conditional grant to receive an Encana common share, or the cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The value of one RSU is notionally equivalent to one Encana common share. RSUs vest three years from the date granted, provided the employee remains actively employed with Encana on the vesting date. As at December 31, 2014, Encana plans to settle the RSUs in cash on the vesting date.

The following tables summarize information related to the RSUs:


(thousands of units)	Canadian Dollar Denominated Outstanding RSUs
As at December 31	2014			2013

Unvested and Outstanding, Beginning of Year		5,130			1,966
Granted		2,785			3,873
Units, in Lieu of Dividends		94			205
Vested and Released		(1,368	)		—
Forfeited		(754	)		(914	)

Unvested and Outstanding, End of Year		5,887			5,130


(thousands of units)	U.S. Dollar Denominated Outstanding RSUs
As at December 31	2014			2013

Unvested and Outstanding, Beginning of Year		3,475			1,596
Granted		1,767			2,458
Units, in Lieu of Dividends		51			139
Vested and Released		(1,071	)		—
Forfeited		(1,112	)		(718	)

Unvested and Outstanding, End of Year		3,110			3,475

As at December 31, 2014, there was approximately $57 million of total unrecognized compensation costs (2013 – $71 million) related to unvested RSUs held by Encana employees. The costs are expected to be recognized over a weighted average period of 1.5 years.

During the year, Encana recorded compensation costs of $36 million related to the outstanding RSUs (2013 – $45 million; 2012 – $25 million). As at December 31, 2014, $11 million of the paid in surplus balance related to the RSUs (2013 – $13 million).

H) RESTRICTED CASH PLAN

In October 2011, Encana’s Board approved the use of a Restricted Cash Plan as a component of the long-term incentive grant to eligible employees, excluding executive officers. The Restricted Cash Plan is a time-based conditional grant to receive cash which, in accordance with the corresponding grant agreement, requires that the employee remains actively employed with Encana on the vesting date. The Restricted Cash Plan vests over three years with one-third payable after each anniversary of the grant date. During the year, Encana recorded compensation costs of $1 million (2013 – $6 million; 2012 – $18 million) related to the Restricted Cash Plan grant. As at December 31, 2014, there are no remaining obligations associated with the Restricted Cash Plan.

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21. PENSION AND OTHER POST-EMPLOYMENT BENEFITS

The Company sponsors defined benefit and defined contribution plans and provides pension and other post-employment benefits (“OPEB”) to its employees in Canada and the U.S. As of January 1, 2003, the defined benefit pension plan was closed to new entrants. The average remaining service period of active employees participating in the defined benefit pension plan is four years. The average remaining service period of the active employees participating in the OPEB plan is 13 years.

The Company is required to file an actuarial valuation of its pension plans with the provincial regulator at least every three years, or more frequently if directed by the regulator. The most recent filing was dated December 31, 2013 and the next required filing is expected to be as at December 31, 2016.

The following tables set forth changes in the benefit obligations and fair value of plan assets for the Company’s defined benefit pension and other post-employment benefit plans for the years ended December 31, 2014 and 2013, as well as the funded status of the plans and amounts recognized in the Consolidated Financial Statements as at December 31, 2014 and 2013.


	Pension Benefits						OPEB
As at December 31	2014			2013			2014			2013

Change in Benefit Obligations
Projected Benefit Obligation, Beginning of Year	$	287		$	357		$	93		$	105
Service cost		3			4			10			12
Interest cost		12			12			4			4
Actuarial (gains) losses		19			(22	)		14			(6	)
Exchange differences		(22	)		(19	)		(3	)		—
Employee contributions		—			—			1			—
Benefits paid		(20	)		(22	)		(5	)		(4	)
Plan amendment		—			—			—			(13	)
Settlement		—			(26	)		—			—
Curtailment		—			—			—			(5	)
Special termination benefits		—			3			—			—

Projected Benefit Obligation, End of Year	$	279		$	287		$	114		$	93


Change in Plan Assets
Fair Value of Plan Assets, Beginning of Year	$	291		$	309		$	—		$	—
Actual return on plan assets		26			40			—			—
Exchange differences		(25	)		(21	)		—			—
Employee contributions		—			—			1			—
Employer contributions		2			12			4			4
Benefits paid		(20	)		(22	)		(5	)		(4	)
Transfers to defined contribution plan		(10	)		—			—			—
Settlement		—			(26	)		—			—
Special termination benefits		—			(1	)		—			—

Fair Value of Plan Assets, End of Year	$	264		$	291		$	—		$	—

Funded Status of Plan Assets, End of Year	$	(15	)	$	4		$	(114	)	$	(93	)


Total Recognized Amounts in the Consolidated Balance Sheet Consist of:
Other assets	$	4		$	10		$	—		$	—
Current liabilities		—			—			(7	)		(6	)
Non-current liabilities		(19	)		(6	)		(107	)		(87	)

Total	$	(15	)	$	4		$	(114	)	$	(93	)


Total Recognized Amounts in Accumulated Other Comprehensive Income Consist of:
Net actuarial (gain) loss	$	44		$	37		$	9		$	(6	)
Prior service costs		(5	)		(6	)		(7	)		(8	)

Total recognized in accumulated other comprehensive income, before tax	$	39		$	31		$	2		$	(14	)

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The accumulated defined benefit obligation for all defined benefit plans was $374 million as at December 31, 2014 (2013 – $362 million). The following sets forth the defined benefit plans with accumulated benefit obligation and projected benefit obligation in excess of the plan assets fair value:


	Pension Benefits						OPEB
As at December 31	2014			2013			2014			2013

Projected Benefit Obligation	$	(279	)	$	(87	)	$	(114	)	$	(93	)
Accumulated Benefit Obligation		(260	)		(72	)		(114	)		(93	)
Fair Value of Plan Assets		260			81			—			—

Following are the weighted average assumptions used by the Company in determining the defined benefit pension and other post-employment benefit obligations:


	Pension Benefits						OPEB
As at December 31	2014			2013			2014			2013

Discount Rate		3.75	%		4.50	%		3.67	%		4.45	%
Rates of Increase in Compensation Levels		3.99	%		3.99	%		6.39	%		6.38	%

The following sets forth total benefit plan expense recognized by the Company in 2014, 2013 and 2012:


	Pension Benefits						OPEB
For the years ended December 31	2014		2013		2012		2014		2013		2012

Defined Benefit Plan Expense	$	—	$	21	$	6	$	12	$	11	$	18
Defined Contribution Plan Expense		34		43		44		—		—		—

Total Benefit Plans Expense	$	34	$	64	$	50	$	12	$	11	$	18

Of the total benefit plans expense, $36 million (2013 – $60 million; 2012 – $55 million) was included in operating expense and $10 million (2013 – $15 million; 2012 – $13 million) was included in administrative expense.

The defined periodic pension and OPEB expense are as follows:


	Pension Benefits									OPEB
For the years ended December 31	2014			2013			2012			2014			2013			2012

Current service cost	$	3		$	4		$	5		$	10		$	12		$	14
Interest cost		12			12			14			4			4			4
Expected return on plan assets		(15	)		(16	)		(28	)		—			—			—
Amounts reclassified from accumulated other comprehensive income:
Amortization of net actuarial (gains) and losses		—			11			15			(1	)		—			—
Amortization of net prior service costs		—			—			—			(1	)		—			—
Settlement		—			5			—			—			—			—
Curtailment		—			1			—			—			(5	)		—
Special termination benefits		—			4			—			—			—			—

Total Defined Benefit Plan Expense	$	—		$	21		$	6		$	12		$	11		$	18

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The amounts recognized in other comprehensive income are as follows:


	Pension Benefits								OPEB
For the years ended December 31	2014		2013			2012			2014		2013			2012

Net actuarial (gains) losses	$	8	$	(46	)	$	2		$	14	$	(6	)	$	(5	)
Plan amendment		—		—			—			—		(13	)		—
Amortization of net actuarial gains and losses		—		(11	)		(15	)		1		—			—
Amortization of net prior service costs		—		—			—			1		—			—
Settlement and curtailment		—		(6	)		—			—		—			—

Total amounts recognized in other comprehensive (income) loss, before tax	$	8	$	(63	)	$	(13	)	$	16	$	(19	)	$	(5	)

Total amounts recognized in other comprehensive (income) loss, after tax	$	6	$	(46	)	$	(9	)	$	11	$	(14	)	$	(4	)

The estimated net actuarial loss and net prior service costs for the pension and other post-retirement plans that will be amortized from accumulated other comprehensive income into net benefit plan expense in 2015 is $2 million.

Following are the weighted average assumptions used by the Company in determining the net periodic pension and other post-retirement benefit costs for 2014, 2013 and 2012.


	Pension Benefits									OPEB
For the years ended December 31	2014			2013			2012			2014			2013			2012

Discount Rate		4.50	%		4.25	%		4.00	%		4.49	%		3.59	%		4.31	%
Long-Term Rate of Return on Plan Assets		6.50	%		6.75	%		6.75	%		—			—			—
Rates of Increase in Compensation Levels		3.99	%		3.99	%		4.11	%		6.50	%		6.35	%		6.41	%

The Company’s assumed health care cost trend rates are as follows:


For the years ended December 31	2014			2013			2012

Health care cost trend rate for next year		7.00	%		7.31	%		7.70	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)		4.59	%		4.61	%		4.63	%
Year that the rate reaches the ultimate trend rate		2024			2026			2025

A one percent change in the assumed health care cost trend rate over the projected period would have the following effects:


	1% Increase		1% Decrease

Effect on total of service and interest cost components	$	1	$	(1	)
Effect on other post-retirement benefit obligations	$	8	$	(7	)

The Company expects to contribute $10 million to its defined benefit pension plans in 2015. The Company’s OPEB plans are funded on an as required basis.

The following provides an estimate of benefit payments for the next 10 years. These estimates reflect benefit increases due to continuing employee service.


	Defined Benefit Pension Payments		Other Benefit Payments

2015	$	18	$	7
2016		18		7
2017		18		8
2018		18		9
2019		18		9
2020 - 2024		90		47

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The Company’s defined benefit pension plan assets are presented by investment asset category and input level within the fair value hierarchy as follows:


As at December 31	2014
	Level 1		Level 2		Level 3		Total

Investments:
Cash and Cash Equivalents	$	34	$	1	$	—	$	35
Fixed Income - Canadian Bond Funds		—		82		—		82
Equity - Domestic		20		50		—		70
Equity - International		—		64		—		64
Real Estate and Other		1		—		12		13

Fair Value of Plan Assets, End of Year	$	55	$	197	$	12	$	264


As at December 31	2013
	Level 1		Level 2		Level 3		Total

Investments:
Cash and Cash Equivalents	$	51	$	1	$	—	$	52
Fixed Income - Canadian Bond Funds		—		57		—		57
Equity - Domestic		35		62		—		97
Equity - International		—		71		—		71
Real Estate and Other		1		—		13		14

Fair Value of Plan Assets, End of Year	$	87	$	191	$	13	$	291

Fixed income investments consist of Canadian bonds issued by investment grade companies. Equity investments consist of both domestic and international securities. The fair values of these securities are based on dealer quotes, quoted market prices, and net asset values as provided by the investment managers. Real Estate and Other consists mainly of commercial properties and is valued based on a discounted cash flow model.


	Real Estate and Other
As at December 31	2014			2013
Balance, Beginning of Year	$	13		$	13
Purchases, issuances and settlements
Purchases		—			—
Settlements		—			—
Actual return on plan assets
Relating to assets sold during the reporting period		—			—
Relating to assets still held at the reporting date		(1	)		—

Balance, End of Year	$	12		$	13

The Company’s pension plan assets were invested in the following as at December 31, 2014: 26 percent Domestic Equity (2013 – 39 percent), 24 percent Foreign Equity (2013 – 29 percent), 44 percent Bonds (2013 – 26 percent), and 6 percent Real Estate and Other (2013 – 6 percent). The expected long-term rate of return is 6.50 percent. The expected rate of return on pension plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The actual return on plan assets was $26 million (2013 – $40 million). The asset allocation structure is subject to diversification requirements and constraints, which reduce risk by limiting exposure to individual equity investment, credit rating categories and foreign currency exposure.

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22. FAIR VALUE MEASUREMENTS

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of those instruments except for the amounts associated with share units issued as part of the Split Transaction, as disclosed below. The fair value of cash in reserve approximates its carrying amount due to the nature of the instrument held. Fair value information related to pension plan assets is included in Note 21.

Recurring fair value measurements are performed for risk management assets and liabilities and for share units resulting from the Split Transaction, which are discussed further in Notes 23 and 20, respectively. These items are carried at fair value in the Consolidated Balance Sheet and are classified within the three levels of the fair value hierarchy in the following tables. There have been no transfers between the hierarchy levels during the period.


As at December 31, 2014	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
Risk Management Assets
Current	$	—	$	718	$	—	$	718	$	(11	)	$	707
Long-term		—		67		—		67		(2	)		65
Risk Management Liabilities
Current		6		14		11		31		(11	)		20
Long-term		—		2		7		9		(2	)		7

As at December 31, 2013	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
Risk Management Assets
Current	$	—	$	71	$	—	$	71	$	(15	)	$	56
Long-term		—		204		—		204		—			204
Risk Management Liabilities
Current		—		38		2		40		(15	)		25
Long-term		—		—		5		5		—			5

Share Units Resulting from the Split Transaction
Encana Share Units Held by Cenovus Employees ⁽²⁾	$	—	$	—	$	—	$	—	$	—		$	—
Cenovus Share Units Held by Encana Employees
Accounts payable and accrued liabilities ⁽³⁾		—		—		8		8		—			8

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

(2)	There were no remaining Encana share units held by Cenovus employees as at December 31, 2014 (2013 – 3.9 million share units with a weighted average exercise price of C$29.06).

(3)	There were no remaining Cenovus share units held by Encana employees as at December 31, 2014.

The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts and basis swaps with terms to 2018. 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.

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LEVEL 3 FAIR VALUE MEASUREMENTS

As at December 31, 2014, the Company’s Level 3 risk management assets and liabilities consist of power purchase contracts with terms to 2017. The fair values of the power purchase contracts are based on the income approach and are modelled internally using observable and unobservable inputs such as forward power prices in less active markets. The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness.

Changes in amounts related to risk management assets and liabilities are recognized in revenues and transportation and processing expense according to their purpose. Changes in amounts related to share units resulting from the Split Transaction are recognized in operating expense, administrative expense and capitalized within property, plant and equipment as described in Note 20.

A summary of changes in Level 3 fair value measurements during 2014 and 2013 is presented below:


	Risk Management						Share Units Resulting from Split Transaction
	2014			2013			2014			2013

Balance, Beginning of Year	$	(7	)	$	(12	)	$	(8	)	$	(36	)
Total gains (losses)		(19	)		3			3			16
Purchases, issuances and settlements:
Purchases		—			—			—			—
Settlements		8			2			5			12
Transfers in and out of Level 3		—			—			—			—

Balance, End of Year	$	(18	)	$	(7	)	$	—		$	(8	)

Change in unrealized gains (losses) related to assets and liabilities held at end of year	$	(13	)	$	(2	)	$	—		$	20

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


	Valuation Technique	Unobservable Input	2014	2013

Risk Management - Power	Discounted Cash Flow	Forward prices ($/Megawatt Hour)	$40.70 - $48.50	$49.25 - $54.47
Share Units Resulting from the Split Transaction	Option Model	Cenovus share unit volatility	—	27.75%

A 10 percent increase or decrease in estimated forward power prices would cause a corresponding $5 million (2013 – $7 million) increase or decrease to net risk management assets and liabilities. As at December 31, 2014, all share units resulting from the Split Transaction have expired. As at December 31, 2013, a five percentage point increase or decrease in Cenovus share unit estimated volatility would cause no increase or decrease to accounts payable and accrued liabilities.

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23. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

A) FINANCIAL INSTRUMENTS

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

B) RISK MANAGEMENT ASSETS AND LIABILITIES

Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value. See Note 22 for a discussion of fair value measurements.

UNREALIZED RISK MANAGEMENT POSITION


As at December 31	2014		2013

Risk Management Assets
Current	$	707	$	56
Long-term		65		204

		772		260

Risk Management Liabilities
Current		20		25
Long-term		7		5

		27		30

Net Risk Management Assets	$	745	$	230

SUMMARY OF UNREALIZED RISK MANAGEMENT POSITIONS – BY PRODUCT


As at December 31	2014							2013
	Risk Management							Risk Management
	Asset		Liability		Net			Asset		Liability		Net

Commodity Prices
Natural gas	$	609	$	5	$	604		$	183	$	15	$	168
Crude oil		163		4		159			77		8		69
Power		—		18		(18	)		—		7		(7	)

Total Fair Value	$	772	$	27	$	745		$	260	$	30	$	230

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COMMODITY PRICE POSITIONS AS AT DECEMBER 31, 2014

Notional Volumes

Term

Average Price

Fair Value

Natural Gas Contracts

Fixed Price Contracts

NYMEX Fixed Price

1,062

MMcf/d

2015

4.29

US$/Mcf

487

Basis Contracts ⁽¹⁾

2015-2018

120

Other Financial Positions

)

Natural Gas Fair Value Position

604

Crude Oil Contracts

Fixed Price Contracts

WTI Fixed Price

12.3

Mbbls/d

2015

92.88

US$/bbl

161

WTI Fixed Price

1.2

Mbbls/d

2016

92.35

US$/bbl

Basis Contracts ⁽²⁾

2015-2016

(16

)

Crude Oil Fair Value Position

159

Power Purchase Contracts

Fair Value Position

(18

)

Total Fair Value

745

(1)	Encana has entered into swaps to protect against widening natural gas price differentials between benchmark and regional sales prices. These basis swaps are priced using differentials determined as a percentage of NYMEX.

(2)	Encana has entered into swaps to protect against widening Brent and Midland differentials to WTI. These basis swaps are priced using fixed price differentials.

EARNINGS IMPACT OF REALIZED AND UNREALIZED GAINS (LOSSES) ON RISK MANAGEMENT POSITIONS


	Realized Gain (Loss)
For the years ended December 31	2014			2013			2012

Revenues, Net of Royalties	$	(84	)	$	544		$	2,149
Transportation and Processing		(7	)		—			12

Gain (Loss) on Risk Management	$	(91	)	$	544		$	2,161


	Unrealized Gain (Loss)
For the years ended December 31	2014			2013			2012

Revenues, Net of Royalties	$	456		$	(347	)	$	(1,441	)
Transportation and Processing		(12	)		2			(24	)

Gain (Loss) on Risk Management	$	444		$	(345	)	$	(1,465	)

RECONCILIATION OF UNREALIZED RISK MANAGEMENT POSITIONS FROM JANUARY 1 TO DECEMBER 31


	2014				2013			2012
	Fair Value		Total Unrealized Gain (Loss)		Total Unrealized Gain (Loss)			Total Unrealized Gain (Loss)

Fair Value of Contracts, Beginning of Year	$	230
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Year		353	$	353	$	199		$	696
Foreign Exchange Translation Adjustment on Canadian Dollar Contracts		1
Fair Value of Athlon Crude Oil Contracts Acquired		70
Fair Value of Contracts Realized During the Year		91		91		(544	)		(2,161	)

Fair Value of Contracts, End of Year	$	745	$	444	$	(345	)	$	(1,465	)

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C) RISKS ASSOCIATED WITH FINANCIAL ASSETS AND LIABILITIES

The Company is exposed to financial risks including market risks (such as commodity prices, foreign exchange and interest rates), credit risk and liquidity risk. Future cash flows may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.

COMMODITY PRICE RISK

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

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

Crude Oil – To partially mitigate against crude oil commodity price risk including widening price differentials between North American and world prices, the Company has entered into fixed price contracts and basis swaps.

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

The table below summarizes the sensitivity of the fair value of the Company’s risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting pre-tax net earnings as at December 31 as follows:


	2014						2013
	10% Price Increase			10% Price Decrease			10% Price Increase			10% Price Decrease

Natural gas price	$	(105	)	$	105		$	(441	)	$	441
Crude oil price		(22	)		22			(19	)		19
Power price		5			(5	)		7			(7	)

CREDIT RISK

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies 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 at December 31, 2014, the Company had no significant collateral balances posted or received and there were no credit derivatives in place.

As at December 31, 2014, 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 in Canada and the U.S. or with counterparties having 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 December 31, 2014, approximately 94 percent (2013 – 87 percent) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.

As at December 31, 2014, Encana had three counterparties (2013 – four counterparties) whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. As at December 31, 2014, these counterparties accounted for 16 percent, 16 percent and 15 percent (2013 – 24 percent, 14 percent, 14 percent and 13 percent) of the fair value of the outstanding in-the-money net risk management contracts.

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LIQUIDITY RISK

Liquidity risk arises from the potential that the Company will encounter difficulties in meeting a demand to fund its financial liabilities as they come due. The Company manages liquidity risk using cash and debt management programs.

The Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities and debt and equity capital markets. As at December 31, 2014, the Company had committed revolving bank credit facilities totaling $4.0 billion which include C$3.5 billion ($3.0 billion) on a revolving bank credit facility for Encana and $1.0 billion on a revolving bank credit facility for a U.S. subsidiary, the latter of which remains unused. The facilities remain committed through June 2018. Of the C$3.5 billion ($3.0 billion) revolving bank credit facility, $1.7 billion remained unused and $1.3 billion was drawn to redeem the senior notes assumed by Encana in conjunction with the Athlon acquisition as discussed in Note 13.

Encana also has accessible capacity under a shelf prospectus for up to $6.0 billion, or the equivalent in foreign currencies, the availability of which is dependent on market conditions, to issue up to $6.0 billion of debt and/or equity securities in Canada and/or the U.S. The shelf prospectus expires in July 2016.

The Company believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.

The Company minimizes its liquidity risk by managing its capital structure. The Company’s capital structure consists of 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 to finance internally generated growth as well as potential acquisitions. To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, issue new shares, issue new debt or repay existing debt.

The timing of expected cash outflows relating to financial liabilities is outlined in the table below:


	Less Than 1 Year		1 - 3 Years		4 - 5 Years		6 - 9 Years		Thereafter		Total

Accounts Payable and Accrued Liabilities	$	2,243	$	—	$	—	$	—	$	—	$	2,243
Risk Management Liabilities		20		7		—		—		—		27
Long-Term Debt ⁽¹⁾		396		1,493		3,030		1,610		6,392		12,921

(1)	Principal and interest.

Included in Encana’s long-term debt obligations of $12,921 million at December 31, 2014 are $1,277 million in principal obligations related to LIBOR loans drawn on the credit facility. These amounts are fully supported and Management expects that they will continue to be supported by revolving credit facilities that have no repayment requirements within the next year. The revolving credit facilities are fully revolving for a period of up to five years. Based on the current maturity dates of the credit facilities, these amounts are included in cash outflows for the period disclosed as 4 – 5 Years. Further information on Long-Term Debt is contained in Note 13.

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 primarily in North America, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Company’s reported results. Encana’s financial results are consolidated in Canadian dollars; however, the Company reports its results in U.S. dollars as most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies. As the effects of foreign exchange fluctuations are embedded in the Company’s results, the total effect of foreign exchange fluctuations is not separately identifiable.

To mitigate the exposure to the fluctuating U.S./Canadian dollar exchange rate, Encana maintains a mix of both U.S. dollar and Canadian dollar debt and may also enter into foreign exchange derivatives. As at December 31, 2014, Encana had $6.7 billion in U.S. dollar debt issued from Canada that was subject to foreign exchange exposure (2013 – $5.4 billion) and $0.6 billion in debt that was not subject to foreign exchange exposure (2013 – $1.7 billion). There were no foreign exchange derivatives outstanding as at December 31, 2014.

Encana’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated debt issued from Canada, unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated risk management assets and liabilities held in Canada and foreign exchange gains and losses on U.S. dollar denominated cash and short-term investments held in Canada. A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $61 million change in foreign exchange (gain) loss as at December 31, 2014 (2013 – $48 million; 2012 – $51 million).

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. There were no interest rate derivatives outstanding as at December 31, 2014.

As at December 31, 2014, the Company had floating rate debt of $1,277 million. Accordingly, the sensitivity in net earnings for each one percent change in interest rates on floating rate debt was $10 million (2013 – nil; 2012 – nil).

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24. SUPPLEMENTARY INFORMATION

A) NET CHANGE IN NON-CASH WORKING CAPITAL


For the years ended December 31	2014			2013			2012

Operating Activities
Accounts receivable and accrued revenues	$	(411	)	$	(75	)	$	82
Accounts payable and accrued liabilities		188			(81	)		(456	)
Income tax payable and receivable		214			(23	)		51

	$	(9	)	$	(179	)	$	(323	)

B) SUPPLEMENTARY CASH FLOW INFORMATION


For the years ended December 31	2014		2013			2012

Interest Paid	$	648	$	575		$	509
Income Taxes Paid, net of Amounts (Recovered)	$	43	$	(186	)	$	(124	)

25. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

The following table outlines the Company’s commitments as at December 31, 2014:


	Expected Future Payments
(undiscounted)	2015		2016		2017		2018		2019		Thereafter		Total

Transportation and Processing	$	878	$	825	$	815	$	800	$	673	$	3,204	$	7,195
Drilling and Field Services		312		138		93		47		16		17		623
Operating Leases		43		36		28		26		10		24		167

Total	$	1,233	$	999	$	936	$	873	$	699	$	3,245	$	7,985

CONTINGENCIES

26. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN

In calculating the standardized measure of discounted future net cash flows, constant price and cost assumptions were applied to Encana’s annual future production from proved reserves to determine cash inflows. Future production and development costs assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The discount was computed by application of a 10 percent discount factor to the future net cash flows. The calculation of the standardized measure of discounted future net cash flows is based upon the discounted future net cash flows prepared by Encana’s independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements, such as price risk management activities, in existence at year end and to account for asset retirement obligations and future income taxes.

Encana cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of Encana’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in oil and natural gas prices, development, asset retirement and production costs, and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates.

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NET PROVED RESERVES ^{(1, 2)}

(12-MONTH AVERAGE TRAILING PRICES; AFTER ROYALTIES)


	Natural Gas (Bcf)									Oil (MMbbls)									NGLs (MMbbls)
	Canada			United States			Total			Canada			United States			Total			Canada			United States			Total
2012
Beginning of year		6,329			6,511			12,840			5.9			38.2			44.1			89.1			—			89.1
Revisions and improved recovery ⁽³⁾		(1,497	)		(1,701	)		(3,198	)		3.0			(5.0	)		(2.0	)		(13.0	)		43.9			30.9
Extensions and discoveries		638			338			976			7.4			19.3			26.7			18.5			19.9			38.4
Purchase of reserves in place		38			8			46			—			0.1			0.1			—			—			—
Sale of reserves in place		(461	)		(321	)		(782	)		(0.7	)		(2.8	)		(3.5	)		(1.5	)		(1.0	)		(2.5	)
Production		(497	)		(593	)		(1,090	)		(2.6	)		(3.8	)		(6.4	)		(4.5	)		(0.4	)		(4.9	)

End of year		4,550			4,242			8,792			13.0			46.0			59.0			88.6			62.4			151.0

Developed		2,985			2,628			5,613			9.9			25.0			34.9			37.9			18.1			56.0
Undeveloped		1,565			1,614			3,179			3.1			21.0			24.1			50.7			44.3			95.0

Total		4,550			4,242			8,792			13.0			46.0			59.0			88.6			62.4			151.0

2013
Beginning of year		4,550			4,242			8,792			13.0			46.0			59.0			88.6			62.4			151.0
Revisions and improved recovery ⁽⁴⁾		(256	)		(362	)		(618	)		2.6			(1.2	)		1.4			(9.6	)		(16.1	)		(25.7	)
Extensions and discoveries		499			482			981			11.5			14.3			25.8			16.7			13.3			30.0
Purchase of reserves in place		—			7			7			—			0.5			0.5			—			0.1			0.1
Sale of reserves in place		(295	)		(1	)		(296	)		—			—			—			(1.5	)		(0.1	)		(1.6	)
Production		(523	)		(491	)		(1,014	)		(4.3	)		(5.1	)		(9.4	)		(6.8	)		(3.5	)		(10.3	)

End of year		3,975			3,877			7,852			22.8			54.5			77.3			87.4			56.1			143.5

Developed		2,744			2,619			5,363			16.5			31.1			47.6			44.6			24.1			68.7
Undeveloped		1,231			1,258			2,489			6.3			23.4			29.7			42.8			32.0			74.8

Total		3,975			3,877			7,852			22.8			54.5			77.3			87.4			56.1			143.5

2014
Beginning of year		3,975			3,877			7,852			22.8			54.5			77.3			87.4			56.1			143.5
Revisions and improved recovery ⁽⁵⁾		250			(511	)		(261	)		(5.0	)		(2.7	)		(7.7	)		10.9			(2.6	)		8.3
Extensions and discoveries		385			493			879			4.7			21.4			26.1			22.3			8.8			31.1
Purchase of reserves in place		6			234			240			—			148.2			148.2			0.1			52.9			53.0
Sale of reserves in place		(885	)		(1,473	)		(2,358	)		(6.6	)		(14.2	)		(20.8	)		(45.5	)		(20.0	)		(65.4	)
Production		(503	)		(355	)		(858	)		(5.0	)		(13.1	)		(18.0	)		(8.6	)		(5.0	)		(13.6	)

End of year		3,229			2,265			5,494			10.9			194.1			205.0			66.6			90.2			156.7

Developed		2,282			1,606			3,887			8.2			112.3			120.5			31.6			53.4			85.0
Undeveloped		947			660			1,607			2.8			81.8			84.5			34.9			36.8			71.7

Total		3,229			2,265			5,494			10.9			194.1			205.0			66.6			90.2			156.7

*	Numbers may not add due to rounding

Notes:

(1)	Definitions:

“Net” reserves are the remaining reserves of Encana, after deduction of estimated royalties and including royalty interests.

“Proved” oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.

“Developed” oil and gas reserves are reserves of any category that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

“Undeveloped” oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)	Encana does not file any estimates of total net proved natural gas, oil and NGLs reserves with any U.S. federal authority or agency other than the Securities and Exchange Commission.

(3)	In 2012, revisions and improved recovery of natural gas included a reduction of 4,589 Bcf due to significantly lower 12-month average trailing natural gas prices, partially offset by additions of 1,391 Bcf for technical revisions and improved recovery.

(4)	In 2013, revisions and improved recovery of natural gas included a reduction of 2,872 Bcf due to lower proved undeveloped reserves bookings, partially offset by additions of 2,233 Bcf due to significantly higher 12-month average trailing natural gas prices and minor positive revisions.

(5)	In 2014, revisions and improved recovery of natural gas included a reduction of 520 Bcf due to changes in the proved undeveloped reserves bookings in the U.S.

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12-MONTH AVERAGE TRAILING PRICES

The following reference prices were utilized in the determination of reserves and future net revenue:


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

Reserves Pricing ⁽¹⁾
2012		2.76		2.35		94.71		87.42
2013		3.67		3.14		96.94		93.44
2014		4.34		4.63		94.99		96.40

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

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES


	Canada						United States
	2014		2013		2012		2014		2013		2012

Future cash inflows		19,255		19,039		15,471		26,742		17,217		14,124
Less future:
Production costs		7,456		7,377		6,273		6,673		4,484		4,095
Development costs		3,276		4,515		5,117		4,087		3,982		4,210
Income taxes		1,727		652		—		2,886		1,615		555

Future net cash flows		6,796		6,495		4,081		13,096		7,136		5,264
Less 10% annual discount for estimated timing of cash flows		2,320		1,836		1,079		6,015		2,978		2,249

Discounted future net cash flows		4,476		4,659		3,002		7,081		4,158		3,015


	Total
	2014		2013		2012

Future cash inflows		45,997		36,256		29,595
Less future:
Production costs		14,129		11,861		10,368
Development costs		7,363		8,497		9,327
Income taxes		4,613		2,267		555

Future net cash flows		19,892		13,631		9,345
Less 10% annual discount for estimated timing of cash flows		8,335		4,814		3,328

Discounted future net cash flows		11,557		8,817		6,017

100 Encana Corporation | Annual Report 2014

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CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES


	Canada									United States
	2014			2013			2012			2014			2013			2012

Balance, beginning of year		4,659			3,002			5,285			4,158			3,015			5,463
Changes resulting from:
Sales of oil and gas produced during the period		(2,120	)		(1,649	)		(1,808	)		(1,746	)		(1,490	)		(2,223	)
Discoveries and extensions, net of related costs		827			725			509			1,429			633			319
Purchases of proved reserves in place		9			—			7			3,052			16			8
Sales and transfers of proved reserves in place		(1,320	)		(304	)		(155	)		(1,902	)		(2	)		(369	)
Net change in prices and production costs		1,777			2,703			(1,364	)		2,567			1,891			(2,106	)
Revisions to quantity estimates		314			(178	)		(1,290	)		(616	)		(324	)		(2,858	)
Accretion of discount		515			311			571			503			333			693
Previously estimated development costs incurred, net of change in future development costs		532			417			946			(3	)		708			3,021
Other		(36	)		14			(7	)		24			(68	)		(79	)
Net change in income taxes		(681	)		(382	)		308			(385	)		(554	)		1,146

Balance, end of year		4,476			4,659			3,002			7,081			4,158			3,015


	Total
	2014			2013			2012

Balance, beginning of year		8,817			6,017			10,748
Changes resulting from:
Sales of oil and gas produced during the period		(3,866	)		(3,139	)		(4,031	)
Discoveries and extensions, net of related costs		2,256			1,358			828
Purchases of proved reserves in place		3,061			16			15
Sales and transfers of proved reserves in place		(3,222	)		(306	)		(524	)
Net change in prices and production costs		4,344			4,594			(3,470	)
Revisions to quantity estimates		(302	)		(502	)		(4,148	)
Accretion of discount		1,018			644			1,264
Previously estimated development costs incurred, net of change in future development costs		529			1,125			3,967
Other		(12	)		(54	)		(86	)
Net change in income taxes		(1,066	)		(936	)		1,454

Balance, end of year		11,557			8,817			6,017

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RESULTS OF OPERATIONS


	Canada							United States
	2014		2013		2012			2014		2013		2012

Oil and gas revenues, net of royalties, transportation and processing		2,475		2,068		2,205			2,244		2,041		2,713
Less:
Operating costs, production and mineral taxes, and accretion of asset retirement obligations		355		419		397			498		551		490
Depreciation, depletion and amortization		625		601		748			992		818		1,102
Impairments		—		—		1,822			—		—		2,842

Operating income (loss)		1,495		1,048		(762	)		754		672		(1,721	)
Income taxes		376		264		(191	)		273		243		(623	)

Results of operations		1,119		784		(571	)		481		429		(1,098	)


	Total
	2014		2013		2012

Oil and gas revenues, net of royalties, transportation and processing		4,719		4,109		4,918
Less:
Operating costs, production and mineral taxes, and accretion of asset retirement obligations		853		970		887
Depreciation, depletion and amortization		1,617		1,419		1,850
Impairments		—		—		4,664

Operating income (loss)		2,249		1,720		(2,483	)
Income taxes		649		507		(814	)

Results of operations		1,600		1,213		(1,669	)

CAPITALIZED COSTS


	Canada						United States
	2014		2013		2012		2014		2013		2012

Proved oil and gas properties		18,271		25,003		26,024		24,279		26,529		24,825
Unproved oil and gas properties		478		598		716		5,655		470		579

Total capital cost		18,749		25,601		26,740		29,934		26,999		25,404
Accumulated DD&A		16,566		23,012		23,962		16,260		22,074		21,236

Net capitalized costs		2,183		2,589		2,778		13,674		4,925		4,168


	Other						Total
	2014		2013		2012		2014		2013		2012

Proved oil and gas properties		65		71		104		42,615		51,603		50,953
Unproved oil and gas properties		—		—		—		6,133		1,068		1,295

Total capital cost		65		71		104		48,748		52,671		52,248
Accumulated DD&A		65		71		104		32,891		45,157		45,302

Net capitalized costs		—		—		—		15,857		7,514		6,946

102 Encana Corporation | Annual Report 2014

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COSTS INCURRED


	Canada						United States ^{(1, 2)}
	2014		2013		2012		2014		2013		2012

Acquisitions
Unproved		15		26		121		5,452		111		235
Proved		6		2		18		5,008		45		5

Total acquisitions		21		28		139		10,460		156		240
Exploration costs		10		22		201		38		412		633
Development costs		1,216		1,343		1,366		1,247		871		1,094

Total costs incurred		1,247		1,393		1,706		11,745		1,439		1,967


	Total ^{(1, 2)}
	2014		2013		2012

Acquisitions
Unproved		5,467		137		356
Proved		5,014		47		23

Total acquisitions		10,481		184		379
Exploration costs		48		434		834
Development costs		2,463		2,214		2,460

Total costs incurred		12,992		2,832		3,673

(1)	2014 Unproved includes $5,338 million from the acquisition of Athlon.

(2)	2014 Proved includes $2,127 million from the acquisition of Athlon.

COSTS NOT SUBJECT TO DEPLETION OR AMORTIZATION

Upstream costs in respect of significant unproved properties are excluded from the country cost centre’s depletable base as follows:


As at December 31	2014		2013

Canada	$	478	$	598
United States		5,655		470

	$	6,133	$	1,068

The following is a summary of the costs related to Encana’s unproved properties as at December 31, 2014:


	2014		2013		2012		Prior to 2012		Total
Acquisition Costs	$	5,474	$	140	$	124	$	253	$	5,991
Exploration Costs		51		41		31		19		142

	$	5,525	$	181	$	155	$	272	$	6,133

Ultimate recoverability of these costs and the timing of inclusion within the applicable country cost centre’s depletable base is dependent upon either the finding of proved natural gas and liquids reserves, expiration of leases or recognition of impairments. Acquisition costs primarily include costs incurred to acquire or lease properties. Exploration costs primarily include costs related to geological and geophysical studies and costs of drilling and equipping exploratory wells.

Annual Report 2014 | Encana Corporation 103

SUPPLEMENTAL INFORMATION

For the period ended December 31, 2014 (U.S. Dollars/U.S. Protocol)

SUPPLEMENTAL FINANCIAL INFORMATION (unaudited)

FINANCIAL RESULTS


($ millions, except per share amounts)	2014															2013
	Year			Q4			Q3			Q2			Q1			Year			Q4			Q3			Q2			Q1

Cash Flow ⁽¹⁾		2,934			377			807			656			1,094			2,581			677			660			665			579
Per share - Diluted ⁽³⁾		3.96			0.51			1.09			0.89			1.48			3.50			0.91			0.89			0.90			0.79
Operating Earnings ⁽²⁾		1,002			35			281			171			515			802			226			150			247			179
Per share - Diluted ⁽³⁾		1.35			0.05			0.38			0.23			0.70			1.09			0.31			0.20			0.34			0.24
Net Earnings (Loss) Attributable to Common Shareholders		3,392			198			2,807			271			116			236			(251	)		188			730			(431	)
Per share - Diluted ⁽³⁾		4.58			0.27			3.79			0.37			0.16			0.32			(0.34	)		0.25			0.99			(0.59	)

Effective Tax Rate using
Canadian Statutory Rate		25.7	%														25.1	%
Foreign Exchange Rates (US$ per C$1)
Average		0.905			0.881			0.918			0.917			0.906			0.971			0.953			0.963			0.977			0.992
Period end		0.862			0.862			0.892			0.937			0.905			0.940			0.940			0.972			0.951			0.985

Cash Flow Summary
Cash From (Used in) Operating Activities		2,667			261			696			767			943			2,289			462			935			554			338
Deduct (Add back):
Net change in other assets and liabilities		(43	)		(15	)		(11	)		(8	)		(9	)		(80	)		(21	)		(15	)		(22	)		(22	)
Net change in non-cash working capital		(9	)		(141	)		155			119			(142	)		(179	)		(183	)		300			(81	)		(215	)
Cash tax on sale of assets		(215	)		40			(255	)		—			—			(33	)		(11	)		(10	)		(8	)		(4	)

Cash Flow ⁽¹⁾		2,934			377			807			656			1,094			2,581			677			660			665			579


Operating Earnings Summary
Net Earnings (Loss) Attributable to Common Shareholders		3,392			198			2,807			271			116			236			(251	)		188			730			(431	)
After-tax (addition) deduction:
Unrealized hedging gain (loss)		306			341			160			8			(203	)		(232	)		(209	)		(89	)		332			(266	)
Impairments		—			—			—			—			—			(16	)		—			(16	)		—			—
Restructuring charges		(24	)		(4	)		(5	)		(5	)		(10	)		(64	)		(64	)		—			—			—
Non-operating foreign exchange gain (loss)		(407	)		(151	)		(218	)		156			(194	)		(282	)		(124	)		105			(162	)		(101	)
Gain (loss) on divestitures		2,523			(11	)		2,399			135			—			—			—			—			—			—
Income tax adjustments		(8	)		(12	)		190			(194	)		8			28			(80	)		38			313			(243	)

Operating Earnings ⁽²⁾		1,002			35			281			171			515			802			226			150			247			179

(1)	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 cash tax on sale of assets.

(2)

Operating Earnings is a non-GAAP measure defined as net earnings attributable to common shareholders excluding non-recurring or non-cash items that Management believes reduces the comparability of the Company’s financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.

(3)	Net earnings attributable to common shareholders, operating earnings and cash flow per common share are calculated using the weighted average number of Encana common shares outstanding as follows:


	2014										2013
(millions)	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Weighted Average Common Shares Outstanding
Basic		741.0		741.1		741.1		741.0		741.0		737.7		740.4		738.3		736.1		736.2
Diluted		741.0		741.1		741.1		741.0		741.0		737.7		740.4		738.3		736.1		736.2

104 Encana Corporation | Annual Report 2014

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SUPPLEMENTAL FINANCIAL & OPERATING INFORMATION (unaudited)


Financial Metrics	2014			2013
	Year			Year

Debt to Debt Adjusted Cash Flow		2.1x			2.4x
Debt to Adjusted Capitalization		30	%		36	%

The financial metrics disclosed above are non-GAAP measures monitored by Management as indicators of the Company’s overall financial strength. These non-GAAP measures are defined and calculated in the Non-GAAP Measures section of Encana’s Management’s Discussion and Analysis.


Net Capital Investment	2014													2013
($ millions)	Year			Q4		Q3			Q2		Q1			Year			Q4			Q3			Q2			Q1

Capital Investment
Canadian Operations		1,226			302		293			350		281			1,365			354			301			301			409
USA Operations		1,285			548		305			206		226			1,283			343			330			327			283
Market Optimization		—			—		(2	)		1		1			3			1			—			2			—
Corporate & Other		15			7		2			3		3			61			19			10			9			23

Capital Investment		2,526			857		598			560		511			2,712			717			641			639			715

Net Acquisitions & (Divestitures) ⁽¹⁾		(1,329	)		50		(2,007	)		652		(24	)		(776	)		(72	)		(51	)		(312	)		(341	)

Net Capital Investment		1,197			907		(1,409	)		1,212		487			1,936			645			590			327			374

(1)	Q1 2013 Net Acquisitions & (Divestitures) includes proceeds received from the sale of the Company’s 30 percent interest in the proposed Kitimat liquefied natural gas export terminal in British Columbia and associated undeveloped lands in the Horn River Basin.


Capital Investment	2014											2013
($ millions)	Year		Q4		Q3			Q2		Q1		Year		Q4		Q3		Q2		Q1

Capital Investment
Montney		776		157		205			208		206		565		186		136		107		136
Duvernay		328		118		58			81		71		155		68		11		28		48
Eagle Ford		274		149		113			12		—		—		—		—		—		—
Permian		117		117		—			—		—		—		—		—		—		—
DJ Basin		277		81		68			69		59		181		46		55		50		30
San Juan		287		96		89			50		52		166		33		61		46		26

		2,059		718		533			420		388		1,067		333		263		231		240

Other Upstream Operations ⁽¹⁾		452		132		65			136		119		1,581		364		368		397		452
Market Optimization		—		—		(2	)		1		1		3		1		—		2		—
Corporate & Other		15		7		2			3		3		61		19		10		9		23

Capital Investment		2,526		857		598			560		511		2,712		717		641		639		715

(1)	Other Upstream Operations includes capital investment for Encana’s base production properties as well as capital investment for prospective plays which are under appraisal, including the Tuscaloosa Marine Shale (“TMS”). 2014 capital investment for the TMS was $101 million (2013 – $98 million).

Annual Report 2014 | Encana Corporation 105

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Production Volumes - After Royalties	2014										2013
(average)	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1

Natural Gas (MMcf/d)		2,350		1,861		2,199		2,541		2,809		2,777		2,744		2,723		2,766		2,877
Oil (Mbbls/d)		49.4		68.8		62.1		34.2		32.1		25.8		33.0		27.2		22.9		20.0
NGLs (Mbbls/d)		37.4		37.6		41.9		34.0		35.8		28.1		33.0		31.0		24.7		23.5

Oil & NGLs (Mbbls/d)		86.8		106.4		104.0		68.2		67.9		53.9		66.0		58.2		47.6		43.5

Total (MBOE/d)		478.5		416.7		470.6		491.8		536.1		516.7		523.4		512.1		508.6		523.0


Production Volumes - After Royalties	2014										2013
(average)	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1

Natural Gas (MMcf/d)
Canadian Operations		1,378		1,111		1,374		1,463		1,568		1,432		1,528		1,414		1,364		1,422
USA Operations		972		750		825		1,078		1,241		1,345		1,216		1,309		1,402		1,455

		2,350		1,861		2,199		2,541		2,809		2,777		2,744		2,723		2,766		2,877

Oil (Mbbls/d)
Canadian Operations		13.6		9.4		14.7		13.9		16.4		11.9		16.8		12.3		10.3		8.0
USA Operations		35.8		59.4		47.4		20.3		15.7		13.9		16.2		14.9		12.6		12.0

		49.4		68.8		62.1		34.2		32.1		25.8		33.0		27.2		22.9		20.0

NGLs (Mbbls/d)
Canadian Operations		23.6		18.8		27.6		23.5		24.6		18.5		21.7		20.5		15.7		16.0
USA Operations		13.8		18.8		14.3		10.5		11.2		9.6		11.3		10.5		9.0		7.5

		37.4		37.6		41.9		34.0		35.8		28.1		33.0		31.0		24.7		23.5

Oil & NGLs (Mbbls/d)
Canadian Operations		37.2		28.2		42.3		37.4		41.0		30.4		38.5		32.8		26.0		24.0
USA Operations		49.6		78.2		61.7		30.8		26.9		23.5		27.5		25.4		21.6		19.5

		86.8		106.4		104.0		68.2		67.9		53.9		66.0		58.2		47.6		43.5

Total (MBOE/d)
Canadian Operations		266.9		213.4		271.4		281.4		302.4		269.0		293.2		268.5		253.3		261.1
USA Operations		211.6		203.3		199.2		210.4		233.7		247.7		230.2		243.6		255.3		261.9

		478.5		416.7		470.6		491.8		536.1		516.7		523.4		512.1		508.6		523.0


Oil & NGLs Production Volumes - After Royalties	2014				2013
(average Mbbls/d)	Year		% of Total		Year		% of Total

Oil		49.4		57		25.8		49
Plant Condensate		12.0		14		8.7		16
Butane		6.8		8		4.5		8
Propane		10.2		11		7.2		13
Ethane		8.4		10		7.7		14

		86.8		100		53.9		100

106 Encana Corporation | Annual Report 2014

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SUPPLEMENTAL FINANCIAL & OPERATING INFORMATION (unaudited)

RESULTS OF OPERATIONS

Product and Operational Information, Including the Impact of Realized Financial Hedging


	2014														2013
($ millions)	Year			Q4		Q3			Q2			Q1			Year		Q4		Q3			Q2		Q1
Natural Gas - Canadian Operations
Revenues, Net of Royalties, excluding Hedging		2,468			402		480			569			1,017			1,771		509		381			459		422
Realized Financial Hedging Gain (Loss)		(74	)		25		20			(44	)		(75	)		271		84		102			19		66
Expenses
Production and mineral taxes		5			2		1			—			2			4		2		1			—		1
Transportation and processing		773			177		186			209			201			724		207		183			165		169
Operating		279			57		66			72			84			322		82		72			80		88

Operating Cash Flow		1,337			191		247			244			655			992		302		227			233		230

Natural Gas - USA Operations
Revenues, Net of Royalties, excluding Hedging		1,640			274		307			463			596			1,872		426		440			547		459
Realized Financial Hedging Gain (Loss)		(85	)		13		10			(43	)		(65	)		260		80		84			27		69
Expenses
Production and mineral taxes		44			11		(10	)		14			29			77		19		16			27		15
Transportation and processing		651			149		162			177			163			722		175		184			179		184
Operating		235			52		50			65			68			339		97		78			78		86

Operating Cash Flow		625			75		115			164			271			994		215		246			290		243

Natural Gas - Total Operations
Revenues, Net of Royalties, excluding Hedging		4,108			676		787			1,032			1,613			3,643		935		821			1,006		881
Realized Financial Hedging Gain (Loss)		(159	)		38		30			(87	)		(140	)		531		164		186			46		135
Expenses
Production and mineral taxes		49			13		(9	)		14			31			81		21		17			27		16
Transportation and processing		1,424			326		348			386			364			1,446		382		367			344		353
Operating		514			109		116			137			152			661		179		150			158		174

Operating Cash Flow		1,962			266		362			408			926			1,986		517		473			523		473

Oil & NGLs - Canadian Operations
Revenues, Net of Royalties, excluding Hedging		872			149		251			227			245			722		222		204			156		140
Realized Financial Hedging Gain (Loss)		18			24		(1	)		(5	)		—			5		6		(7	)		2		4
Expenses
Production and mineral taxes		10			—		3			4			3			11		2		7			1		1
Transportation and processing		62			16		16			16			14			32		18		7			4		3
Operating		28			10		8			4			6			39		7		11			9		12

Operating Cash Flow		790			147		223			198			222			645		201		172			144		128

Oil & NGLs - USA Operations
Revenues, Net of Royalties, excluding Hedging		1,258			412		452			215			179			602		177		169			134		122
Realized Financial Hedging Gain (Loss)		60			65		1			(6	)		—			4		3		(7	)		3		5
Expenses
Production and mineral taxes		74			23		23			15			13			42		14		11			9		8
Transportation and processing		7			3		4			—			—			—		—		—			—		—
Operating		115			51		44			12			8			59		10		12			14		23

Operating Cash Flow		1,122			400		382			182			158			505		156		139			114		96

Oil & NGLs - Total Operations
Revenues, Net of Royalties, excluding Hedging		2,130			561		703			442			424			1,324		399		373			290		262
Realized Financial Hedging Gain (Loss)		78			89		—			(11	)		—			9		9		(14	)		5		9
Expenses
Production and mineral taxes		84			23		26			19			16			53		16		18			10		9
Transportation and processing		69			19		20			16			14			32		18		7			4		3
Operating		143			61		52			16			14			98		17		23			23		35

Operating Cash Flow		1,912			547		605			380			380			1,150		357		311			258		224

Annual Report 2014 | Encana Corporation 107

LOGO

SUPPLEMENTAL OIL AND GAS OPERATING STATISTICS (unaudited)

OPERATING STATISTICS - AFTER ROYALTIES

Per-unit Results, Excluding the Impact of Realized Financial Hedging


	2014											2013
	Year		Q4		Q3			Q2		Q1		Year		Q4		Q3		Q2		Q1
Natural Gas - Canadian Operations ($/Mcf)
Price ⁽¹⁾		4.89		3.93		3.78			4.27		7.17		3.35		3.60		2.90		3.69		3.21
Production and mineral taxes		0.01		0.01		0.01			—		0.01		0.01		0.02		0.01		—		0.01
Transportation and processing		1.53		1.73		1.47			1.57		1.42		1.37		1.46		1.38		1.33		1.29
Operating		0.55		0.55		0.52			0.55		0.59		0.61		0.59		0.55		0.65		0.66

Netback		2.80		1.64		1.78			2.15		5.15		1.36		1.53		0.96		1.71		1.25

Natural Gas - USA Operations ($/Mcf)
Price		4.62		3.95		4.05			4.72		5.34		3.81		3.81		3.66		4.29		3.50
Production and mineral taxes		0.12		0.17		(0.14	)		0.15		0.26		0.16		0.18		0.13		0.21		0.11
Transportation and processing		1.83		2.16		2.13			1.80		1.46		1.47		1.56		1.53		1.40		1.40
Operating		0.66		0.75		0.65			0.67		0.61		0.69		0.86		0.65		0.61		0.66

Netback		2.01		0.87		1.41			2.10		3.01		1.49		1.21		1.35		2.07		1.33

Natural Gas - Total Operations ($/Mcf)
Price ⁽²⁾		4.78		3.94		3.88			4.46		6.37		3.57		3.69		3.26		3.99		3.35
Production and mineral taxes		0.06		0.08		(0.05	)		0.06		0.12		0.08		0.09		0.07		0.11		0.06
Transportation and processing		1.66		1.90		1.72			1.67		1.44		1.42		1.51		1.46		1.36		1.35
Operating		0.60		0.63		0.57			0.60		0.60		0.65		0.70		0.60		0.63		0.66

Netback		2.46		1.33		1.64			2.13		4.21		1.42		1.39		1.13		1.89		1.28

Oil & NGLs - Canadian Operations ($/bbl)
Price		64.16		57.50		64.79			66.13		66.36		65.06		62.80		67.33		65.88		64.72
Production and mineral taxes		0.71		0.10		0.67			1.12		0.80		0.96		0.61		1.91		0.62		0.58
Transportation and processing		4.52		5.92		4.21			4.60		3.80		2.89		5.15		2.41		1.53		1.33
Operating		2.09		4.00		2.05			1.06		1.75		3.56		2.03		3.74		3.77		5.61

Netback		56.84		47.48		57.86			59.35		60.01		57.65		55.01		59.27		59.96		57.20

Oil & NGLs - USA Operations ($/bbl)
Price		69.54		57.30		79.43			77.46		73.61		70.18		69.46		72.53		68.56		69.91
Production and mineral taxes		4.10		3.16		4.18			5.19		5.46		4.79		5.06		4.90		4.57		4.50
Transportation and processing		0.39		0.49		0.63			—		—		—		—		—		—		—
Operating		6.36		7.11		7.80			4.29		3.16		7.02		4.11		5.13		7.54		13.16

Netback		58.69		46.54		66.82			67.98		64.99		58.37		60.29		62.50		56.45		52.25

Oil & NGLs - Total Operations ($/bbl)
Price		67.24		57.35		73.48			71.23		69.23		67.30		65.58		69.60		67.10		67.04
Production and mineral taxes		2.65		2.35		2.75			2.95		2.65		2.63		2.46		3.22		2.41		2.33
Transportation and processing		2.16		1.93		2.09			2.53		2.30		1.63		3.01		1.36		0.84		0.73
Operating		4.54		6.29		5.46			2.51		2.31		5.07		2.90		4.35		5.48		8.98

Netback		57.89		46.78		63.18			63.24		61.97		57.97		57.21		60.67		58.37		55.00

108 Encana Corporation | Annual Report 2014

LOGO

SUPPLEMENTAL OIL AND GAS OPERATING STATISTICS (unaudited)

OPERATING STATISTICS - AFTER ROYALTIES (continued)

Per-unit Results, Excluding the Impact of Realized Financial Hedging


	2014										2013
	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Total Operations Netback - Canadian Operations ($/BOE)
Price		34.21		28.06		29.21		31.02		46.20		25.13		27.02		23.42		26.62		23.34
Production and mineral taxes		0.15		0.09		0.15		0.16		0.18		0.15		0.17		0.29		0.05		0.09
Transportation and processing		8.55		9.79		8.10		8.76		7.87		7.62		8.31		7.60		7.30		7.16
Operating		3.14		3.39		2.96		2.98		3.29		3.65		3.32		3.34		3.88		4.13

Netback		22.37		14.79		18.00		19.12		34.86		13.71		15.22		12.19		15.39		11.96

Total Operations Netback - USA Operations ($/BOE)
Price		37.53		36.64		41.38		35.48		36.82		27.37		28.42		27.23		29.35		24.61
Production and mineral taxes		1.53		1.84		0.72		1.51		1.99		1.31		1.54		1.22		1.55		0.97
Transportation and processing		8.52		8.17		9.03		9.23		7.75		7.98		8.24		8.24		7.69		7.80
Operating		4.53		5.51		5.12		4.05		3.60		4.42		5.06		4.04		3.97		4.65

Netback		22.95		21.12		26.51		20.69		23.48		13.66		13.58		13.73		16.14		11.19

Total Operations Netback ($/BOE)
Price		35.67		32.25		34.36		32.93		42.12		26.20		27.63		25.23		27.99		23.97
Production and mineral taxes		0.76		0.94		0.39		0.74		0.97		0.71		0.77		0.73		0.80		0.53
Transportation and processing		8.54		9.00		8.50		8.96		7.82		7.79		8.28		7.90		7.50		7.48
Operating ⁽³⁾		3.76		4.43		3.87		3.44		3.43		4.01		4.08		3.67		3.92		4.38

Netback		22.61		17.88		21.60		19.79		29.90		13.69		14.50		12.93		15.77		11.58

(1)	Canadian Operations price reflects Deep Panuke price for 2014 of $8.34/Mcf on natural gas production volumes of 190 MMcf/d. Excluding the impact of the Deep Panuke operations, the natural gas price for 2014 is $4.35/Mcf.

(2)	Excluding the impact of the Deep Panuke operations, the natural gas price for 2014 is $4.47/Mcf.

(3)	2014 operating expense includes costs related to long-term incentives of $0.06/BOE (2013 – $0.08/BOE).

Impact of Realized Financial Hedging


	2014														2013
	Year			Q4		Q3			Q2			Q1			Year		Q4		Q3			Q2		Q1
Natural Gas ($/Mcf)
Canadian Operations		(0.15	)		0.24		0.16			(0.33	)		(0.53	)		0.51		0.60		0.78			0.15		0.50
USA Operations		(0.24	)		0.19		0.12			(0.44	)		(0.58	)		0.53		0.72		0.69			0.21		0.53
Total Operations		(0.19	)		0.22		0.15			(0.38	)		(0.55	)		0.52		0.65		0.74			0.18		0.51
Oil & NGLs ($/bbl)
Canadian Operations		1.36			9.35		(0.31	)		(1.22	)		(0.09	)		0.46		1.62		(2.59	)		1.00		2.20
USA Operations		3.29			8.94		0.25			(2.28	)		0.04			0.44		1.15		(2.73	)		1.32		2.67
Total Operations		2.46			9.05		0.02			(1.70	)		(0.04	)		0.45		1.43		(2.65	)		1.15		2.41
Total ($/BOE)
Canadian Operations		(0.57	)		2.49		0.78			(1.89	)		(2.77	)		2.78		3.32		3.78			0.91		2.93
USA Operations		(0.33	)		4.15		0.58			(2.57	)		(3.07	)		2.93		3.96		3.44			1.28		3.14
Total Operations		(0.46	)		3.30		0.70			(2.18	)		(2.90	)		2.85		3.60		3.62			1.09		3.03

Annual Report 2014 | Encana Corporation 109

LOGO

SUPPLEMENTAL OIL AND GAS OPERATING STATISTICS (unaudited)

OPERATING STATISTICS - AFTER ROYALTIES (continued)

Per-unit Results, Including the Impact of Realized Financial Hedging


	2014										2013
	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Natural Gas Price ($/Mcf)
Canadian Operations		4.74		4.17		3.94		3.94		6.64		3.86		4.20		3.68		3.84		3.71
USA Operations		4.38		4.14		4.17		4.28		4.76		4.34		4.53		4.35		4.50		4.03
Total Operations		4.59		4.16		4.03		4.08		5.82		4.09		4.34		4.00		4.17		3.86
Natural Gas Netback ($/Mcf)
Canadian Operations		2.65		1.88		1.94		1.82		4.62		1.87		2.13		1.74		1.86		1.75
USA Operations		1.77		1.06		1.53		1.66		2.43		2.02		1.93		2.04		2.28		1.86
Total Operations		2.27		1.55		1.79		1.75		3.66		1.94		2.04		1.87		2.07		1.79
Oil & NGLs Price ($/bbl)
Canadian Operations		65.52		66.85		64.48		64.91		66.27		65.52		64.42		64.74		66.88		66.92
USA Operations		72.83		66.24		79.68		75.18		73.65		70.62		70.61		69.80		69.88		72.58
Total Operations		69.70		66.40		73.50		69.53		69.19		67.75		67.01		66.95		68.25		69.45
Oil & NGLs Netback ($/bbl)
Canadian Operations		58.20		56.83		57.55		58.13		59.92		58.11		56.63		56.68		60.96		59.40
USA Operations		61.98		55.48		67.07		65.70		65.03		58.81		61.44		59.77		57.77		54.92
Total Operations		60.35		55.83		63.20		61.54		61.93		58.42		58.64		58.02		59.52		57.41
Total Price ($/BOE)
Canadian Operations		33.64		30.55		29.99		29.13		43.43		27.91		30.34		27.20		27.53		26.27
USA Operations		37.20		40.79		41.96		32.91		33.75		30.30		32.38		30.67		30.63		27.75
Total Operations		35.21		35.55		35.06		30.75		39.22		29.05		31.23		28.85		29.08		27.00
Total Netback ($/BOE)
Canadian Operations		21.80		17.28		18.78		17.23		32.09		16.49		18.54		15.97		16.30		14.89
USA Operations		22.62		25.27		27.09		18.12		20.41		16.59		17.54		17.17		17.42		14.33
Total Operations		22.15		21.18		22.30		17.61		27.00		16.54		18.10		16.55		16.86		14.61

110 Encana Corporation | Annual Report 2014

LOGO

SUPPLEMENTAL OIL AND GAS OPERATING STATISTICS (unaudited)

RESULTS BY PLAY


	2014											2013
	Year		Q4			Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Natural Gas Production (MMcf/d) - After Royalties
Canadian Operations
Montney		514		570			517		484		484		463		500		513		424		413
Duvernay		11		12			15		9		8		4		7		5		2		1
Other Upstream Operations ⁽¹⁾
Clearwater		292		249			291		305		324		335		329		332		331		347
Bighorn		158		(3	)		162		230		246		255		283		253		242		243
Deep Panuke		190		79			186		243		253		41		133		30		—		—
Other and emerging		213		204			203		192		253		334		276		281		365		418

Total Canadian Operations		1,378		1,111			1,374		1,463		1,568		1,432		1,528		1,414		1,364		1,422

USA Operations
Eagle Ford		19		35			35		5		—		—		—		—		—		—
Permian		5		20			—		—		—		—		—		—		—		—
DJ Basin		43		49			38		43		40		39		43		37		39		37
San Juan		8		8			9		7		7		3		6		3		1		1
Other Upstream Operations ⁽¹⁾
Piceance		402		367			398		407		436		455		452		444		465		459
Haynesville		311		252			298		365		331		348		261		336		375		420
Jonah		100		—			—		124		282		323		296		320		332		346
East Texas		57		—			21		97		113		136		123		132		145		145
Other and emerging		27		19			26		30		32		41		35		37		45		47

Total USA Operations		972		750			825		1,078		1,241		1,345		1,216		1,309		1,402		1,455

Oil & NGLs Production (Mbbls/d) - After Royalties
Canadian Operations
Montney		18.7		24.6			20.7		13.3		16.1		10.0		13.5		11.8		7.8		6.7
Duvernay		2.1		2.5			2.6		1.8		1.4		0.7		1.2		0.7		0.5		0.3
Other Upstream Operations ⁽¹⁾
Clearwater		8.6		2.0			9.9		11.3		11.3		9.9		12.2		9.8		9.2		8.5
Bighorn		7.5		(1.5	)		8.7		11.0		12.1		8.9		10.9		9.9		7.4		7.4
Other and emerging		0.3		0.6			0.4		—		0.1		0.9		0.7		0.6		1.1		1.1

Total Canadian Operations		37.2		28.2			42.3		37.4		41.0		30.4		38.5		32.8		26.0		24.0

USA Operations
Eagle Ford		19.8		36.1			37.6		5.0		—		—		—		—		—		—
Permian		3.5		13.8			—		—		—		—		—		—		—		—
DJ Basin		11.6		14.0			11.8		10.1		10.5		8.4		10.7		8.2		7.8		6.8
San Juan		3.9		5.6			3.5		3.9		2.7		1.4		2.9		1.9		0.4		0.3
Other Upstream Operations ⁽¹⁾
Piceance		5.0		4.3			4.8		5.3		5.4		5.1		5.3		5.5		5.2		4.3
Jonah		1.8		—			0.2		2.5		4.7		4.7		4.6		4.8		4.9		4.6
East Texas		0.5		—			—		1.0		1.2		1.0		1.0		1.1		0.9		0.8
Other and emerging		3.5		4.4			3.8		3.0		2.4		2.9		3.0		3.9		2.4		2.7

Total USA Operations		49.6		78.2			61.7		30.8		26.9		23.5		27.5		25.4		21.6		19.5

(1)	Other Upstream Operations includes results from plays that are not part of the Company’s current strategic focus as well as prospective plays which are under appraisal, including the TMS which is reported in Other and emerging in the USA Operations.

Annual Report 2014 | Encana Corporation 111

LOGO

SUPPLEMENTAL OIL AND GAS OPERATING STATISTICS (unaudited)

RESULTS BY PLAY (continued)


	2014										2013
	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Drilling Activity (net wells drilled)
Canadian Operations
Montney		79		14		15		23		27		61		18		14		13		16
Duvernay		24		5		7		6		6		12		4		4		2		2
Other Upstream Operations ⁽¹⁾
Clearwater		174		84		24		—		66		283		115		81		—		87
Bighorn		1		—		1		—		—		21		1		3		9		8
Other and emerging		1		—		1		—		—		13		2		2		5		4

Total Canadian Operations		279		103		48		29		99		390		140		104		29		117

USA Operations
Eagle Ford		35		21		14		—		—		—		—		—		—		—
Permian		28		28		—		—		—		—		—		—		—		—
DJ Basin		64		15		17		14		18		51		11		13		15		12
San Juan		43		19		15		5		4		19		4		7		6		2
Other Upstream Operations ⁽¹⁾
Piceance		1		—		—		—		1		85		20		20		23		22
Haynesville		—		—		—		—		—		19		7		5		5		2
Jonah		18		—		—		6		12		49		9		13		13		14
East Texas		—		—		—		—		—		7		3		2		—		2
Other and emerging		15		5		4		4		2		7		2		2		—		3

Total USA Operations		204		88		50		29		37		237		56		62		62		57

(1)	Other Upstream Operations includes net wells drilled in plays that are not part of the Company’s current strategic focus as well as prospective plays which are under appraisal, including the TMS which is reported in Other and emerging in the USA Operations.

112 Encana Corporation | Annual Report 2014

STRONG LEADERSHIP / OUR EXECUTIVE LEADERSHIP AND BOARD

EXECUTIVE LEADERSHIP TEAM

BOARD OF DIRECTORS

Doug Suttles

President & Chief Executive Officer

Doug Suttles joined Encana as President & CEO in June 2013. With 30 years of experience in the oil and gas industry in various engineering and leadership roles, he is responsible for the overall success of Encana and for creating, planning, implementing, and integrating the strategic direction of the organization.

Sherri Brillon

Executive Vice-President & Chief Financial Officer

Responsible for the development and execution of a disciplined and dynamic capital allocation process strongly linked to the company’s strategic direction and the provision of financial expertise across the organization.

David Hill

Executive Vice-President, Exploration & Business Development

Responsible for reviewing the company’s asset base and ensuring Encana has the right assets today and in the future as well as securing a top-tier resource portfolio for the company.

Joanne Alexander

Executive Vice-President & General Counsel

Responsible for the overall legal affairs of Encana and its subsidiaries and overseeing the company’s corporate compliance program.

Mike McAllister

Executive Vice-President & Chief Operating Officer

Responsible for Encana’s upstream and production activities across the company’s assets and tasked with relentlessly pursuing greater efficiency and operational excellence.

Ryder McRitchie

Vice-President, Investor Relations & Communications

Responsible for the communications, community involvement, government relations, and policy, environment and sustainability groups. Each of these play an important role in supporting Encana’s operations and uniting the Encana brand throughout North America and ensuring all of our communications are aligned with our strategy.

Mike Williams

Executive Vice-President, Corporate Services

Responsible for overseeing Encana’s Corporate Services including the information technology, human resources, administration services, business office and travel & meetings groups.

Reneé Zemljak

Executive Vice-President, Midstream, Marketing & Fundamentals

Responsible for driving strategic direction through industry-leading market fundamentals, maintaining Encana’s status as a supplier of choice and maximizing profitability through optimization of netback prices.

Clayton Woitas

Calgary, Alberta

Peter Dea

Denver, Colorado

Fred Fowler

Houston, Texas

Howard Mayson

Breckenridge, Colorado

Lee McIntire

Denver, Colorado

Suzanne Nimocks

Houston, Texas

Jane Peverett

West Vancouver, British Columbia

Brian Shaw

Toronto, Ontario

Doug Suttles

Calgary, Alberta

Bruce Waterman

Calgary, Alberta

Annual Report 2014 | Encana Corporation 113

CORPORATE AND

INVESTOR INFORMATION / TO OUR SHAREHOLDERS

TRANSFER AGENTS AND REGISTRAR

COMMON SHARES

CST Trust Company

Calgary, Montreal and Toronto

Computershare

Jersey City, New Jersey

Shareholders are encouraged to contact

CST Trust Company for information regarding security holdings.

Answerline: 416.682.3863

Toll-free (North America): 1.866.580.7145

Facsimile: 1.888.249.6189

MAILING ADDRESS

CST Trust Company

P.O. Box 700, Station B

Montreal, Quebec, Canada H3B 3K3

INTERNET ADDRESS

www.canstockta.com

AUDITOR

PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta

INDEPENDENT QUALIFIED RESERVES EVALUATORS

Cawley, Gillespie & Associates, Inc.

Fort Worth, Texas

GLJ Petroleum Consultants Ltd.

Calgary, Alberta

McDaniel & Associates Consultants Ltd.

Calgary, Alberta

Netherland, Sewell & Associates, Inc.

Dallas, Texas

STOCK EXCHANGES

COMMON SHARES (ECA)

Toronto Stock Exchange

New York Stock Exchange

ANNUAL INFORMATION FORM (AIF) (FORM 40-F)

Encana’s AIF is filed with the securities regulators in Canada and the United States. Under the Multi-Jurisdictional Disclosure System, Encana’s AIF is filed as Form 40-F with the U.S. Securities and Exchange Commission.

SHAREHOLDER ACCOUNT MATTERS

To change your address, transfer shares, eliminate duplicate mailings, have dividends deposited directly into accounts at financial institutions in Canada that provide electronic fund-transfer services, etc., please contact CST Trust Company.

ANNUAL SHAREHOLDERS’ MEETING OF SHAREHOLDERS

Shareholders are invited to attend the Annual & Special Meeting of Shareholders being held on Tuesday, May 12, 2015 at 10 a.m. Calgary time at:

Palomino Room

BMO Centre (formerly the Roundup Centre)

Stampede Park, 20 Roundup Way SE Calgary, Alberta, Canada

Those unable to attend are asked to vote by proxy on the internet, by telephone or by fax or to sign and return the form of proxy mailed to them.

ENCANA WEBSITE

www.encana.com

Encana’s website contains a variety of corporate and investor information, including, among other information, the following:

•

Current stock prices

•

Annual and Interim Reports

•

Information Circulars

•

News releases

•

Investor presentations

•

Dividend information

•

Dividend reinvestment plan

•

Shareholder support information

•

Corporate Responsibility information

Additional information, including copies of the Encana Corporation 2014 Annual Report, may be obtained from Encana Corporation.

ENCANA CORPORATION

Investor Relations & Communications 500 Centre Street SE, P.O. Box 2850 Calgary, Alberta, Canada T2P 2S5

Phone: 403.645.3550

Email: investor.relations@encana.com

Web: www.encana.com

INVESTOR INQUIRIES SHOULD BE DIRECTED TO:

Brian Dutton

Director, Investor Relations

Phone: 403.645.2285

Email: brian.dutton@encana.com

Patti Posadowksi

Senior Investor Relations Advisor

Phone: 403.645.2252

Email: patti.posadowski@encana.com

114 Encana Corporation | Annual Report 2014

ABBREVIATIONS / 2014 ANNUAL REPORT



bbls	barrels	MMbbls/d	million barrels per day
bbls/d	barrels per day	Mcf	thousand cubic feet
BOE	barrels of oil equivalent	MM	million
Bcf	billion cubic feet	MMcf	million cubic feet
Bcf/d	billion cubic feet per day	MMcf/d	million cubic feet per day
Mbbls	thousand barrels	NGLs	natural gas liquids
Mbbls/d	thousand barrels per day	Tcf	trillion cubic feet
MMbbls	million barrels	/d	per day