Edgar Filing: ENCANA CORP

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of
of the Securities Exchange Act of 1934


For: February 15, 2007		Commission File Number: 1-15226

ENCANA CORPORATION

(Translation of registrant’s name into English)

1800, 855 — 2^nd Street SW
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 o Form 40-F þ

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): o

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): o

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:

Yes o No þ

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-o

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: February 15, 2007

		ENCANA CORPORATION (Registrant)

	By:	/s/ Linda H. Mackid Name: Linda H. Mackid
		Title: Assistant Corporate Secretary

Form 6-K Exhibit Index


Exhibit No.

99.1		News release dated February 15, 2007 referenced as:

		“EnCana generates 2006 cash flow of US$7.2 billion, or $8.56 per share”

EnCana generates 2006 cash flow of US$7.2 billion,
or $8.56 per share

Proved reserves additions replace close to 200% of North American production

Quarterly dividend doubled to 20 cents per share

Calgary, Alberta, (February 15, 2007) – EnCana Corporation (TSX & NYSE: ECA) today reports a 3 percent increase in 2006 cash flow per share diluted to US$8.56, or $7.2 billion. Total operating earnings per share diluted in 2006 increased 7 percent to $3.91, or $3.27 billion. Net earnings per share diluted were $6.76, or $5.65 billion, which includes after-tax gains of $2.38 billion due to unrealized mark-to-market accounting for commodity price hedges, gains on sales of discontinued operations and tax rate changes.

Natural gas and oil reserves added through drilling replaced 197 percent of EnCana’s 2006 production in continuing operations and increased North American proved reserves by 9 percent to 19.2 trillion cubic feet of gas equivalent (Tcfe). Finding and development costs in total operations were $1.99 per thousand cubic feet equivalent (Mcfe).

Strong financials, resource play production grows 12 percent

“EnCana achieved strong financial results and solid operating performance in 2006. We continued to fortify our future by adding close to double the proved reserves that we produced in 2006, at a competitive cost of about $2 per thousand cubic feet equivalent. Our natural gas production was up 4 percent, while our key resource play production grew 12 percent year-over-year. We achieved all this in a tough operating environment for the industry marked by record breaking activity levels,” said Randy Eresman, EnCana’s President & Chief Executive Officer.

Transformation to unconventional gas and oil complete

“The year also marked the completion of EnCana’s transformation into essentially a pure North American producer focused on unconventional natural gas and integrated oilsands – a strategic position that we believe will create sustainable profitable growth for our company. All of EnCana’s production and reserves are now onshore North America,” Eresman said.

Dividend doubled

“As a reflection of our increased confidence in the sustainable nature of our North American unconventional business model, the board of directors has doubled our quarterly dividend to 20 cents per share,” Eresman said.

IMPORTANT NOTE: EnCana reports in U.S. dollars unless otherwise noted and follows U.S. protocols, which report production, sales and reserves on an after-royalties basis. The company is reporting its Ecuador operations and its natural gas storage business as discontinued because EnCana sold them. Total results, which include results from Ecuador and natural gas storage, are reported in the company’s financial statements included in this news release and in supplementary documents posted on its website – www.encana.com. The company’s financial statements are prepared in accordance with Canadian generally accepted accounting principles (GAAP).

2006 Highlights

Financial

	•		Cash flow per share diluted increased 3 percent to $8.56

	•		Operating earnings per share diluted up 7 percent to $3.91

	•		Net earnings per share diluted up 76 percent to $6.76

	•		Generated $892 million in free cash flow (as defined in Note 1 on page 8)

	•		Net divestitures of $3.0 billion, resulting in net capital investment of $3.3 billion

	•		Purchased 85.6 million EnCana shares at an average share price of $49.26 under the Normal Course Issuer Bid for a total cost of $4.2 billion

	•		Reduced shares outstanding at year end by 9 percent, net of share option exercises

	•		At year end, net debt-to-adjusted-EBITDA was 0.6 times and net debt-to-capitalization was 27 percent

Operating

	•		Key resource play production up 12 percent

	•		Natural gas production of 3.37 billion cubic feet per day (Bcf/d), up 4 percent

	•		Oil and natural gas liquids (NGLs) production of about 167,100 barrels per day (bbls/d), down 26 percent, primarily due to the sale of Ecuador oil assets, which produced an average of 12,366 bbls/d in 2006

	•		Operating costs of 86 cents per thousand cubic feet equivalent (Mcfe) for continuing operations, up 21 percent due to inflation, a stronger Canadian dollar and higher electricity costs

	•		Upstream capital investment in continuing operations of $6.2 billion

Reserves

	•		Added 3.1 Tcfe of proved reserves with drill bit additions and revisions in continuing operations

	•		Added 2.3 Tcfe of proved reserves in total operations, taking into account the sale of about 822 billion cubic feet equivalent (Bcfe) of proved reserves largely as a result of the Ecuador divestiture

	•		Proved reserves additions included 160 million bbls (960 Bcfe) at the Foster Creek and Christina Lake oilsands key resource plays

	•		Proved reserves increased 9 percent in continuing operations and 4 percent in total operations to 19.2 Tcfe

	•		Finding and development (F&D) costs averaged $1.99 per Mcfe for total operations

	•		Production replacement of 197 percent for continuing operations; 144 percent for total operations, which includes the sale of Ecuador reserves

	•		Average three-year reserve replacement cost of $1.56 per Mcfe for continuing operations; $1.34 per Mcfe for total operations

2006 strategic results

	•		Created an integrated heavy oil business with ConocoPhillips composed of two 50/50 entities – one upstream and one downstream – which became effective January 2, 2007. The integrated business intends to produce 400,000 barrels of Canadian bitumen and refine 275,000 barrels of bitumen at two U.S. refineries by 2015.

	•		Completed sale of Ecuador assets for $1.1 billion and sale of interest in Brazil oil discovery for proceeds of $367 million

	•		Sold natural gas storage business for $1.5 billion

	•		Received environmental impact statement approval for Jonah gas field, which enables advancing toward full development of this key resource play

Financial Summary — Total Consolidated



(for the period ended December 31)	Q4			Q4
($ millions, except per share amounts)	2006			2005			% D		2006		2005			% D

Cash flow		1,761			2,510			- 30		7,161		7,426			- 4
Per share diluted		2.18			2.88			- 24		8.56		8.35			+ 3

Net earnings		663			2,366			- 72		5,652		3,426			+ 65
Per share diluted		0.82			2.71			- 70		6.76		3.85			+ 76

Operating earnings¹		675			1,271			- 47		3,271		3,241			+ 1
Per share diluted		0.84			1.46			- 42		3.91		3.64			+ 7

Earnings Reconciliation Summary – Total Consolidated

Net earnings from continuing operations		643			1,869			- 66		5,051		2,829			+ 79
Net earnings from discontinued operations		20			497			- 96		601		597			+ 1

Net Earnings		663			2,366			- 72		5,652		3,426			+ 65
(Add back losses & deduct gains)
Unrealized mark-to-market hedging gain (loss), after-tax		95			746					1,370		(277	)

Unrealized foreign exchange gain (loss) on translation of U.S. dollar debt issued in Canada, after-tax		(128	)		(21	)				—		92

Future tax recovery due to Canada and Alberta tax rate reductions		—			—					457		—

Gain on sale of discontinued operations, after-tax²		21			370					554		370

Operating earnings		675			1,271			- 47		3,271		3,241			+ 1
Per share diluted		0.84			1.46			- 42		3.91		3.64			+ 7


¹		Operating earnings is a non-GAAP measure that shows net earnings excluding non-operating items such as the after-tax impacts of the gain on the sale of discontinued operations, the after-tax gain/loss on unrealized mark-to-market accounting for derivative instruments, the after-tax gain/loss on translation of U.S. dollar denominated debt issued in Canada and the effect of the reduction in income tax rates.

²		In 2006, gain on sale of natural gas storage business and loss on sale of Ecuador assets


Cash flow information 2006
(for the period ended December 31, $ millions)	Q4			2006

Cash from Operating Activities		1,697			7,973
Deduct (Add back):
Net change in other assets and liabilities		90			138
Net change in non-cash working capital from continuing operations		39			3,343
Net change in non-cash working capital from discontinued operations		(193	)		(2,669	)

Cash Flow³		1,761			7,161
Cash flow from Discontinued Operations		19			118

Cash flow from Continuing Operations		1,742			7,043


³		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 from continuing operations and net change in non-cash working capital from discontinued operations, all of which are defined in the Consolidated Statement of Cash Flows.

Sales & Drilling Summary

Total Consolidated



(for the period ended December 31)	Q4		Q4
(After royalties)	2006		2005		% D		2006		2005		% D

Natural Gas sales (MMcf/d)		3,406		3,326		+ 2		3,367		3,227		+ 4

Natural gas sales per 1,000 shares (Mcf)		395		358		+ 10		1,499		1,357		+ 10

Oil and NGLs sales (bbls/d)		152,154		229,232		- 34		167,070		227,065		- 26

Oil and NGLs sales per 1,000 shares (Mcfe)		106		148		- 28		446		573		- 22

Total sales (MMcfe/d)		4,319		4,701		- 8		4,369		4,589		- 5

Total sales per 1,000 shares (Mcfe)		501		506		- 1		1,945		1,929		+ 1

Net wells drilled		809		1,146		- 29		3,657		4,676		- 22

Continuing Operations

North America Natural Gas sales (MMcf/d)		3,406		3,326		+ 2		3,367		3,227		+ 4

North America Oil and NGLs (bbls/d)		152,154		159,289		- 4		154,704		156,000		- 1

Total sales (MMcfe/d)		4,319		4,282		+ 1		4,295		4,163		+ 3

Net wells drilled		809		1,138		- 29		3,650		4,658		- 22

Resource play growth

Key resource play production grows 12 percent in 2006

EnCana’s production growth continues to be led by its 12 key resource plays, which grew by about 12 percent in 2006 and comprise about 62 percent of total production. The strongest growth came from the company’s coalbed methane (CBM) production in central and southern Alberta, Bighorn in west central Alberta, Cutbank Ridge in northeast British Columbia and Fort Worth in Texas. In-situ oilsands production from EnCana’s Foster Creek steam-assisted gravity drainage project grew about 27 percent in 2006.

Growth from key North American resource plays



	Daily Production
	2006										2005
	Full										Full
Resource Play	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1

Natural Gas (MMcf/d)
Jonah		464		487		455		450		461		435		454		440		416		431
Piceance		326		335		331		324		316		307		326		302		302		300
East Texas		99		95		106		93		99		90		98		94		85		82
Fort Worth		101		99		104		108		93		70		88		66		63		61
Greater Sierra		213		212		209		224		208		219		226		225		228		195
Cutbank Ridge		170		199		167		173		140		92		125		105		80		56
Bighorn		91		99		97		95		72		55		56		57		53		56
CBM¹		194		211		209		179		177		112		165		117		104		59
Shallow Gas		600		601		593		590		615		625		625		616		633		625

Oil (Mbbls/d)
Foster Creek		37		41		37		33		36		29		35		27		24		30
Christina Lake		6		6		6		6		6		5		5		6		7		4
Pelican Lake		24		20		23		22		29		26		28		27		27		21

Total (MMcfe/d)		2,656		2,740		2,668		2,601		2,609		2,366		2,567		2,381		2,312		2,197

% change from prior year’s period		12.3		6.7		12.1		12.5		18.8		20.0


¹		CBM 2005 volumes restated to report commingled gas volumes from the coal and sand intervals based on regulatory approval.

Drilling activity in key North American resource plays



	Net Wells Drilled
	2006										2005
	Full										Full
Resource Play	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1

Natural Gas
Jonah		163		41		48		48		26		104		21		25		30		28
Piceance		220		50		48		59		63		266		55		69		65		77
East Texas		59		11		12		17		19		84		20		21		22		21
Fort Worth		97		19		22		27		29		59		20		18		12		9
Greater Sierra		115		5		16		34		60		164		25		33		47		59
Cutbank Ridge		116		19		35		36		26		135		34		40		38		23
Bighorn		52		7		7		18		20		51		20		10		10		11
CBM¹		729		157		156		35		381		1,245		344		314		242		345
Shallow Gas		1,164		326		442		199		197		1,267		288		341		365		273

Oil
Foster Creek		6		—		—		—		6		39		13		14		2		10
Christina Lake		2		—		—		—		2		—		—		—		—		—
Pelican Lake		—		—		—		—		—		52		—		3		33		16

Total net wells		2,723		635		786		473		829		3,466		840		888		866		872


¹		CBM 2005 wells restated to report commingled gas drilling from the coal and sand intervals based on regulatory approval.

Year-end 2006 proved reserves

EnCana achieved 9 percent growth in proved reserves from continuing operations at a competitive finding and development cost of less than $2.00 per Mcfe

Total natural gas and liquids proved reserves

	•		Proved reserves increased 4 percent to 19.2 Tcfe

	•		Proved reserves in North America (continuing operations) increased 9 percent

	•		Proved reserves additions were 3.1 Tcfe in continuing operations, compared to production of 1.6 Tcfe

Natural gas reserves

	•		Proved gas reserves increased 5 percent to 12.4 Tcf

	•		Proved gas additions were 1.9 Tcf, compared to production of 1.2 Tcf

	•		Gas production replacement of 152 percent

Oil and NGLs reserves

	•		Proved oil and NGLs reserves in continuing operations increased 15 percent to 1.1 billion bbls

	•		Proved oil and NGLs additions in continuing operations were 205 million bbls, compared to production of 57 million bbls

	•		Oil and NGLs production replacement of 357 percent in continuing operations

Bitumen reserves (included in oil and NGLs)

	•		Bitumen reserves up 22 percent to 800 million bbls

	•		Proved bitumen additions were 160 million bbls compared to production of 17 million bbls

Reserves additions costs

	•		Total three-year reserves replacement cost averaged $1.34 per Mcfe

	•		Total 2006 finding and development cost of $1.99 per Mcfe

All of EnCana’s proved reserves are evaluated by independent qualified reserves evaluators.

2006 Proved Reserves Reconciliation



	Natural gas									Crude oil and Natural Gas Liquids																		Gas Equivalent¹
	(Bcf)									(MMbbls)																		(Bcfe)
										Canada			Canada			Canada															Continuing
	Canada			USA			Total			Conv.			Bitumen			Total			USA			Ecuador			Total			Total			Ops.⁴

Start of 2006		6,517			5,267			11,784			275.1			657.4			932.5			53.1			135.0			1,120.6			18,507			17,697
Revisions & improved recovery		301			(88	)		213			27.5			(66.5	)		(39.0	)		(1.1	)		—			(40.1	)		(27	)		(27	)
Extensions & discoveries		1,014			606			1,620			12.6			226.1			238.7			6.4			—			245.1			3,091			3,091
Acquisitions		—			68			68			—			—			—			0.3			—			0.3			69			69
Divestitures		(6	)		(32	)		(38	)		(0.1	)		—			(0.1	)		—			(130.6	)		(130.7	)		(822	)		(38	)
Production		(798	)		(431	)		(1,229	)		(35.3	)		(17.4	)		(52.7	)		(4.7	)		(4.4	)		(61.8	)		(1,600	)		(1,574	)

End of 2006		7,028			5,390			12,418			279.8			799.6			1,079.4			54.0			—			1,133.4			19,218			19,218

Developed		4,718			2,964			7,682			215.3			101.6			316.9			33.5			—			350.4			9,784			9,784

Undeveloped		2,310			2,426			4,736			64.5			698.0			762.5			20.5			—			783.0			9,434			9,434

Total																													19,218			19,218
-
% Change ²		+ 8			+ 2			+ 5			+ 2			+ 22			+ 16			+ 2						+ 1			+ 4			+ 9

Partnership contribution³		—			—			—			—			(398.0	)		(398.0	)		—			—			(398.0	)		(2,388	)		(2,388	)

Effective Jan. 2, 2007		7,028			5,390			12,418			279.8			401.6			681.4			54.0			—			735.4			16,830			16,830


¹		Gas equivalency has been calculated by EnCana. See the Advisory Regarding Reserves Data and Other Oil and Gas Information accompanying this release.

²		EnCana’s growth in proved reserves in 2006 is expressed as the percentage change from the start to the end of the year.

³		Effective January 2, 2007, EnCana established a heavy oil integration arrangement with ConocoPhillips, resulting in ConocoPhillips acquiring a 50 percent interest in EnCana’s Foster Creek and Christina Lake oilsands projects and EnCana acquiring a 50 percent interest in ConocoPhillips’ Wood River and Borger refineries.

⁴		Continuing operations are composed of North American operations, and exclude the Ecuador assets, which were sold in 2006.

Proved Reserves Costs



											Cumulative
Capital investment	($ millions)	2006			2005			2004			2004-06

Finding and development			6,107			6,231			4,792			17,130
Acquisitions			368			472			3,469			4,309
Divestitures			(1,639	)		(2,552	)		(3,827	)		(8,018	)

Net capital investment			4,836			4,151			4,434			13,421

Total reserve additions	(Bcfe)		2,311			4,542			3,163			10,016

	($/Mcfe)										3-year average

Reserve replacement cost			2.09			0.91			1.40			1.34

Finding, development and acquisition cost			2.07			1.36			1.70			1.66

Finding and development cost			1.99			1.29			1.44			1.52

NOTE: This table excludes the impact of the bitumen reserves revisions of 2004 and bitumen reserves reinstatement in 2005.

2006 natural gas and oil prices

2006 Natural Gas and Oil Prices
(excludes financial hedging)

Natural gas ($/Mcf)

2006

2005

Change

2006

2005

Change

NYMEX Price

6.55

12.96

- 49

7.22

8.62

- 16

EnCana Realized Gas Price

5.79

10.29

- 44

6.25

7.46

- 16

Oil and NGLs ($/bbl)

WTI Price

60.17

60.05

+ 1

66.25

56.70

+ 17

Western Canada Select (WCS)

39.08

36.40

+ 7

44.69

36.39

+ 23

Differential WTI/WCS

21.09

23.65

- 11

21.56

20.31

+ 6

EnCana Realized Liquids Price

38.69

37.16

+ 4

43.71

36.17

+ 21

Price risk management

Detailed risk management positions at December 31, 2006 are presented in Note 14 to the 2006 unaudited interim consolidated financial statements. In 2006, EnCana’s financial price risk management measures resulted in realized gains of approximately $270 million after-tax, composed of a $386 million gain on gas hedges, a $126 million loss on oil hedges and a $10 million gain on other hedges.

More than 50 percent of expected 2007 natural gas and liquids production has downside price protection

In 2007 EnCana has about 1.76 Bcf/d of expected gas production with downside price protection, composed of 1.52 Bcf/d under fixed price contracts at an average NYMEX equivalent price of $8.49 per Mcf and 240 million cubic feet per day with put options at a NYMEX equivalent strike price of $6.00 per Mcf. In oil, EnCana has about 126,000 bbls/d of expected 2007 oil production with downside price protection, composed of 34,500 bbls/d under fixed price contracts at an average West Texas Intermediate (WTI) price of $64.40 per bbl, plus put options on 91,500 bbls/d at an average strike price of WTI $55.34 per bbl. This price hedging strategy helps reduce uncertainty in cash flow during periods of commodity price volatility.

2007 gas production forecast to increase 9 percent per share

In 2007, natural gas production, which represents more than 80 percent of EnCana’s production, is expected to increase about 3 percent, or 9 percent per share based on expected share purchases, to about 3.46 Bcf/d. Oil production is expected to average about 138,000 bbls/d. Total production in 2007, prior to the allocation of oilsands volumes to ConocoPhillips as part of the heavy oil integration, was expected to be up 4 percent. With the creation of the integrated oilsands business, EnCana expects 2007 total production to be about 4.28 Bcfe/d, about the same as in 2006, or an increase of about 4 percent per share.

Corporate developments

Quarterly dividend increased 100 percent to 20 cents per share

EnCana’s board of directors declared a quarterly dividend of 20 cents per share, which is payable on March 30, 2007 to common shareholders of record as of March 15, 2007. This is double the amount of the previous quarterly dividend.

EnCana Normal Course Issuer Bid purchases

In 2006, EnCana purchased about 85.6 million common shares, representing approximately 10 percent of the company’s outstanding shares on December 31, 2005, at an average price of approximately $49.26 per common share. As at December 31, 2006 there were approximately 778 million common shares issued and outstanding in total. EnCana plans to fund its continuing Normal Course Issuer Bid purchases with cash flow and proceeds from potential divestitures. To date in 2007, EnCana has purchased about 10.8 million shares at an average cost of $45.64 per share.

Financial strength

EnCana targets a net debt-to-capitalization ratio between 30 and 40 percent. EnCana’s balance sheet strengthened during 2006. At December 31, 2006, the company’s net debt-to-capitalization ratio was 27:73, down from 33:67 at the end of 2005. EnCana’s net debt-to-adjusted-EBITDA multiple, on a trailing 12-month basis, was 0.6 times at the end of 2006, down from 1.1 times at the end of 2005.

CONFERENCE CALL TODAY

EnCana Corporation will host a conference call and webcast today to discuss fourth quarter and year-end 2006 financial and operating results at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial (877) 704-5384 (toll-free in North America) or (913) 312-1297 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 3:00 p.m. MT on February 15 until midnight February 19, 2007 by dialling (888) 203-1112 or (719) 457-0820 and entering access code 4419778.

A live audio webcast of the conference call will also be available via EnCana’s website, www.encana.com, under Investor Relations. The webcast will be archived for approximately 90 days.

NOTE 1: Non-GAAP measures

This news release contains references to cash flow, total operating earnings and free cash flow.

	•		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 from continuing operations and net change in non-cash working capital from discontinued operations, all of which are defined on the Consolidated Statement of Cash Flows.

	•		Total operating earnings is a non-GAAP measure that shows net earnings excluding non-operating items such as the after-tax impacts of a gain on the sale of discontinued operations, the after-tax gain/loss of unrealized mark-to-market accounting for derivative instruments, the after-tax gain/loss on translation of U.S. dollar denominated debt issued in Canada and the effect of the reduction in income tax rates.

			Management believes that these excluded items reduce the comparability of the company’s underlying financial performance between periods. The majority of the unrealized gains/losses that relate to U.S. dollar debt issued in Canada are for debt with maturity dates in excess of five years.

	•		Free cash flow is a non-GAAP measure that EnCana defines as cash flow in excess of core capital investment.

These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding EnCana’s liquidity and its ability to generate funds to finance its operations.

EnCana Corporation

With an enterprise value of approximately US$45 billion, EnCana is a leading North American unconventional natural gas and integrated oilsands company. By partnering with employees, community organizations and other businesses, EnCana contributes to the strength and sustainability of the communities where it operates. EnCana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.

RESERVES COST DEFINITIONS – Production replacement is calculated by dividing reserves additions by production in the same period. Reserves additions over a given period, in this case 2006, are calculated by summing one or more of revisions and improved recovery, extensions and discoveries, acquisitions and divestitures. Reserve replacement cost is calculated by dividing total capital invested in finding, development and acquisitions net of divestitures by reserve additions in the same period. Finding and development cost is calculated by dividing total capital invested in finding and development activities by additions to proved reserves, before acquisitions and divestitures, which is the sum of revisions, extensions and discoveries. Finding, development and acquisition cost is

calculated by dividing total capital invested in finding, development and acquisition activities by additions to proved reserves, before divestitures, which is the sum of revisions, extensions, discoveries and acquisitions. Proved reserves added in 2006 included both developed and undeveloped quantities. Additions to EnCana’s proved undeveloped reserves were consistent with EnCana’s resource play focus. The company estimates that approximately two-thirds of its proved undeveloped reserves will be developed within the next three to four years. 2006 finding, development and acquisition capital includes investment in long lead time projects. EnCana uses the aforementioned metrics as indicators of relative performance, along with a number of other measures. Many performance measures exist, all measures have limitations and historical measures are not necessarily indicative of future performance.

ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION – EnCana’s disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to EnCana by Canadian securities regulatory authorities which permits it to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). EnCana’s reserves quantities represent net proved reserves calculated using the standards contained in Regulation S-X of the U.S. Securities and Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in EnCana’s Annual Information Form.

In this news release, certain crude oil and NGLs volumes have been converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). Also, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.

Unbooked resource potential

EnCana defines unbooked resource potential as quantities of oil and natural gas on existing landholdings that are not yet classified as proved reserves, but which EnCana believes may be moved into the proved reserves category and produced in the future. EnCana employs a probability-weighted approach in the calculation of these quantities, including statistical distributions of resource play performance and areal extent. Consequently, EnCana’s unbooked resource potential necessarily includes quantities of probable and possible reserves and contingent resources, as these terms are defined in the Canadian Oil and Gas Evaluation Handbook.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS – In the interests of providing EnCana shareholders and potential investors with information regarding EnCana, including management’s assessment of EnCana’s and its subsidiaries’ future plans and operations, certain statements contained in this news release are forward-looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as “forward-looking statements.” Forward-looking statements in this news release include, but are not limited to: future economic and operating performance (including per share growth, cash flow and increase in net asset value); anticipated life of proved reserves; anticipated unbooked resource potential; anticipated conversion of unbooked resource potential to proved reserves; anticipated growth and success of resource plays and the expected characteristics of resource plays; the expected proceeds from planned divestitures; planned expansion of in-situ oilsands production; anticipated crude oil and natural gas prices; anticipated expansion and production at Foster Creek and Christina Lake; anticipated increased capacity for the two U.S. refineries (including by 2015); anticipated drilling inventory; expected proportion of total production and cash flows contributed by natural gas; anticipated success of EnCana’s market risk mitigation strategy and EnCana’s ability to participate in commodity price upside and to provide downside price protection; anticipated purchases pursuant to the Normal Course Issuer Bid; estimated recycle ratios; potential demand for natural gas; anticipated production in 2007 and beyond; anticipated drilling; potential capital expenditures and investment; potential oil, natural gas and NGLs sales in 2007 and beyond; anticipated costs and inflationary pressures; potential risks associated with drilling and references to potential exploration. 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 risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon the company’s current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company’s marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves; the ability of the company and ConocoPhillips to successfully manage and operate the integrated North American heavy oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology; the company’s ability to replace and expand oil and gas reserves; its ability to generate sufficient cash flow from operations to meet its current and future obligations; its 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 environmental and other regulations or the interpretations of such regulations; political and economic conditions in the countries in which the company operates; the risk of war, hostilities, civil insurrection and instability affecting countries in which the company operates and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the company; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. 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 news release are made as of the date of this news release, and, except as required by law, EnCana does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

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


FOR FURTHER INFORMATION:
*Investor contact:*		*Media contact:*
EnCana Corporate Communications
Sheila McIntosh		Alan Boras
Executive Vice-President, Corporate Communications		Manager, Media Relations
(403) 645-2194		(403) 645-4747
Paul Gagne
Manager, Investor Relations
(403) 645-4737
Ryder McRitchie
Manager, Investor Relations
(403) 645-2007

Fourth quarter report
for the period ended December 31, 2006

CONSOLIDATED STATEMENT OF EARNINGS (unaudited)


		Three Months Ended					Twelve Months Ended
		December 31,					December 31,
($ millions, except per share amounts)		2006			2005		2006			2005

REVENUES, NET OF ROYALTIES	(Note 3)
Upstream		$	2,812		$	3,525	$	11,342		$	10,772
Market Optimization			735			1,417		3,007			4,267
Corporate — Unrealized gain (loss) on risk management			129			991		2,050			(466	)

			3,676			5,933		16,399			14,573

EXPENSES	(Note 3)
Production and mineral taxes			80			162		349			453
Transportation and selling			275			211		1,070			845
Operating			428			452		1,655			1,438
Purchased product			702			1,376		2,862			4,159
Depreciation, depletion and amortization			766			751		3,112			2,769
Administrative			84			63		271			268
Interest, net	(Note 6)		142			104		396			524
Accretion of asset retirement obligation	(Note 10)		13			10		50			37
Foreign exchange (gain) loss, net	(Note 7)		172			37		14			(24	)
Stock-based compensation — options			—			3		—			15
(Gain) on divestitures	(Note 5)		(2	)		—		(323	)		—

			2,660			3,169		9,456			10,484


NET EARNINGS BEFORE INCOME TAX			1,016			2,764		6,943			4,089
Income tax expense	(Note 8)		373			895		1,892			1,260

NET EARNINGS FROM CONTINUING OPERATIONS			643			1,869		5,051			2,829
NET EARNINGS FROM DISCONTINUED OPERATIONS	(Note 4)		20			497		601			597

NET EARNINGS		$	663		$	2,366	$	5,652		$	3,426

NET EARNINGS FROM CONTINUING OPERATIONS PER COMMON SHARE	(Note 13)
Basic		$	0.81		$	2.19	$	6.16		$	3.26
Diluted		$	0.80		$	2.14	$	6.04		$	3.18


NET EARNINGS PER COMMON SHARE	(Note 13)
Basic		$	0.84		$	2.77	$	6.89		$	3.95
Diluted		$	0.82		$	2.71	$	6.76		$	3.85

CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)


		Twelve Months Ended
		December 31,
($ millions)		2006			2005

RETAINED EARNINGS, BEGINNING OF YEAR		$	9,481		$	7,935
Net Earnings			5,652			3,426
Dividends on Common Shares			(304	)		(238	)
Charges for Normal Course Issuer Bid	(Note 11)		(3,485	)		(1,642	)

RETAINED EARNINGS, END OF YEAR		$	11,344		$	9,481

See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

CONSOLIDATED BALANCE SHEET (unaudited)

As at

As at

December 31,

December 31,

($ millions)

2006

2005

ASSETS

Current Assets

Cash and cash equivalents

402

105

Accounts receivable and accrued revenues

1,721

1,851

Risk management

(Note 14)

1,403

495

Inventories

176

103

Assets of discontinued operations

(Note 4)

—

1,050

3,702

3,604

Property, Plant and Equipment, net

(Note 3)

28,213

24,881

Investments and Other Assets

533

496

Risk Management

(Note 14)

133

530

Assets of Discontinued Operations

(Note 4)

—

2,113

Goodwill

2,525

2,524

(Note 3)

35,106

34,148

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities

Accounts payable and accrued liabilities

2,494

2,741

Income tax payable

926

392

Risk management

(Note 14)

1,227

Liabilities of discontinued operations

(Note 4)

—

438

Current portion of long-term debt

(Note 9)

257

3,691

4,871

Long-Term Debt

(Note 9)

6,577

6,703

Other Liabilities

Risk Management

(Note 14)

102

Asset Retirement Obligation

(Note 10)

1,051

816

Liabilities of Discontinued Operations

(Note 4)

—

267

Future Income Taxes

6,240

5,289

17,640

18,141

Shareholders’ Equity

Share capital

(Note 11)

4,587

5,131

Paid in surplus

160

133

Retained earnings

11,344

9,481

Foreign currency translation adjustment

1,375

1,262

17,466

16,007

35,106

34,148

See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)


		Three Months Ended						Twelve Months Ended
		December 31,						December 31,
($ millions)		2006			2005			2006			2005

OPERATING ACTIVITIES
Net earnings from continuing operations		$	643		$	1,869		$	5,051		$	2,829
Depreciation, depletion and amortization			766			751			3,112			2,769
Future income taxes	(Note 8)		260			717			950			56
Cash tax on sale of assets	(Note 5)		—			(13	)		49			578
Unrealized (gain) loss on risk management	(Note 14)		(141	)		(985	)		(2,060	)		469
Unrealized foreign exchange (gain) loss			155			28			76			(50	)
Accretion of asset retirement obligation	(Note 10)		13			10			50			37
(Gain) on divestitures	(Note 5)		(2	)		—			(323	)		—
Other			48			13			138			274
Cash flow from discontinued operations			19			120			118			464
Net change in other assets and liabilities			90			(108	)		138			(281	)
Net change in non-cash working capital from continuing operations			39			1,165			3,343			497
Net change in non-cash working capital from discontinued operations			(193	)		(140	)		(2,669	)		(212	)

Cash From Operating Activities			1,697			3,427			7,973			7,430


INVESTING ACTIVITIES
Capital expenditures	(Note 3)		(1,250	)		(2,362	)		(6,600	)		(6,925	)
Proceeds on disposal of assets	(Note 5)		55			30			689			2,523
Cash tax on sale of assets	(Note 5)		—			13			(49	)		(578	)
Net change in investments and other			40			(161	)		2			(109	)
Net change in non-cash working capital from continuing operations			188			165			19			330
Discontinued operations			180			572			2,557			239

Cash (Used in) Investing Activities			(787	)		(1,743	)		(3,382	)		(4,520	)


FINANCING ACTIVITIES
Net issuance (repayment) of revolving long-term debt			646			(1,513	)		134			(538	)
Repayment of long-term debt			—			(145	)		(73	)		(1,104	)
Issuance of long-term debt			—			—			—			429
Issuance of common shares	(Note 11)		39			24			179			294
Purchase of common shares	(Note 11)		(1,246	)		—			(4,219	)		(2,114	)
Dividends on common shares			(78	)		(64	)		(304	)		(238	)
Other			(3	)		(17	)		(11	)		(125	)

Cash (Used in) Financing Activities			(642	)		(1,715	)		(4,294	)		(3,396	)


DEDUCT: FOREIGN EXCHANGE LOSS ON CASH AND CASH EQUIVALENTS HELD IN FOREIGN CURRENCY			—			1			—			2


INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			268			(32	)		297			(488	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			134			137			105			593

CASH AND CASH EQUIVALENTS, END OF YEAR		$	402		$	105		$	402		$	105

See accompanying Notes to Consolidated Financial Statements.



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

1. BASIS OF PRESENTATION

The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries (“EnCana” or the “Company”), and are presented in accordance with Canadian generally accepted accounting principles. EnCana’s continuing operations are in the business of exploration for, and production and marketing of, natural gas, crude oil and natural gas liquids and power generation operations.

The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2005, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. The interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2005.

2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES

On January 1, 2006, the Company adopted Emerging Issues Task Force (“EITF”) Abstract No. 04-13 - Accounting for Purchases and Sales of Inventory with the Same Counterparty. In 2006, purchases and sales of inventory with the same counterparty that are entered into in contemplation of each other are recorded on a net basis in the Consolidated Statement of Earnings. This change has been adopted prospectively and has no effect on the net earnings of the reported periods. As a result of the adoption of this policy, reported Market Optimization revenues and purchased product costs for the three months and twelve months ended December 31, 2006 included offsets of $899 million and $3,238 million, respectively.

3. SEGMENTED INFORMATION

The Company has defined its continuing operations into the following segments:

•

Upstream includes the Company’s exploration for, and development and production of, natural gas, crude oil and natural gas liquids and other related activities. The majority of the Company’s Upstream operations are located in Canada and the United States. Frontier and international new ventures exploration is mainly focused on opportunities in Brazil, the Middle East, Greenland and France.

•

Market Optimization is conducted by the Midstream & Marketing division. The Marketing groups’ primary responsibility is the sale of the Company’s proprietary production. The results are included in the Upstream segment. Correspondingly, the Marketing groups also undertake market optimization activities which comprise third party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment.

•

Corporate includes unrealized gains or losses recorded on derivative instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates.

Market Optimization purchases substantially all of the Company’s North American Upstream production for sale to third party customers. Transactions between business segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.

Operations that have been discontinued are disclosed in Note 4.


Encana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

3. SEGMENTED INFORMATION (continued)

Results of Continuing Operations (For the three months ended December 31)


	Upstream				Market Optimization
	2006		2005		2006			2005

Revenues, Net of Royalties	$	2,812	$	3,525	$	735		$	1,417
Expenses
Production and mineral taxes		80		162		—			—
Transportation and selling		276		208		(1	)		3
Operating		428		415		13			32
Purchased product		—		—		702			1,376
Depreciation, depletion and amortization		743		731		4			1

Segment Income	$	1,285	$	2,009	$	17		$	5


		Corporate *					Consolidated
		2006			2005		2006			2005

Revenues, Net of Royalties		$	129		$	991	$	3,676		$	5,933
Expenses
Production and mineral taxes			—			—		80			162
Transportation and selling			—			—		275			211
Operating			(13	)		5		428			452
Purchased product			—			—		702			1,376
Depreciation, depletion and amortization			19			19		766			751

Segment Income		$	123		$	967		1,425			2,981

Administrative								84			63
Interest, net								142			104
Accretion of asset retirement obligation								13			10
Foreign exchange (gain) loss, net								172			37
Stock-based compensation — options								—			3
(Gain) on divestitures	(Note 5)							(2	)		—

								409			217

Net Earnings Before Income Tax								1,016			2,764
Income tax expense								373			895

Net Earnings From Continuing Operations							$	643		$	1,869


*		For the three months ended December 31, the pre-tax unrealized gain (loss) on risk management is recorded in the Consolidated Statement of Earnings as follows (see Note 14):


	2006		2005

Revenues, Net of Royalties — Corporate	$	129	$	991
Operating Expenses and Other — Corporate		12		(6	)

Total Unrealized Gain on Risk Management before-tax — Continuing Operations	$	141	$	985



EnCana Corporation				Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

3. SEGMENTED INFORMATION (continued)

Results of Continuing Operations (For the three months ended December 31)


*Upstream*	Canada				United States
	2006		2005		2006		2005

Revenues, Net of Royalties	$	1,966	$	2,331	$	765	$	1,106
Expenses
Production and mineral taxes		20		29		60		133
Transportation and selling		210		160		66		48
Operating		276		227		76		64
Depreciation, depletion and amortization		536		511		200		166

Segment Income	$	924	$	1,404	$	363	$	695


	Other						Total Upstream
	2006			2005			2006		2005

Revenues, Net of Royalties	$	81		$	88		$	2,812	$	3,525
Expenses
Production and mineral taxes		—			—			80		162
Transportation and selling		—			—			276		208
Operating		76			124			428		415
Depreciation, depletion and amortization		7			54			743		731

Segment Income (Loss)	$	(2	)	$	(90	)	$	1,285	$	2,009

Upstream Geographic and Product Information (Continuing Operations) (For the three months ended December 31)


	Produced Gas
	Canada				United States				Total
	2006		2005		2006		2005		2006		2005

Revenues, Net of Royalties	$	1,401	$	1,852	$	706	$	1,041	$	2,107	$	2,893
Expenses
Production and mineral taxes		11		20		54		127		65		147
Transportation and selling		66		72		66		48		132		120
Operating		166		144		76		64		242		208

Operating Cash Flow	$	1,158	$	1,616	$	510	$	802	$	1,668	$	2,418


	Oil & NGLs
	Canada				United States				Total
	2006		2005		2006		2005		2006		2005

Revenues, Net of Royalties	$	565	$	479	$	59	$	65	$	624	$	544
Expenses
Production and mineral taxes		9		9		6		6		15		15
Transportation and selling		144		88		—		—		144		88
Operating		110		83		—		—		110		83

Operating Cash Flow	$	302	$	299	$	53	$	59	$	355	$	358


	Other					Total Upstream
	2006		2005			2006		2005

Revenues, Net of Royalties	$	81	$	88		$	2,812	$	3,525
Expenses
Production and mineral taxes		—		—			80		162
Transportation and selling		—		—			276		208
Operating		76		124			428		415

Operating Cash Flow	$	5	$	(36	)	$	2,028	$	2,740



EnCana Corporation				Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31,2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

3. SEGMENTED INFORMATION (continued)

Results of Continuing Operations (For the twelve months ended December 31)


	Upstream				Market Optimization
	2006		2005		2006		2005

Revenues, Net of Royalties	$	11,342	$	10,772	$	3,007	$	4,267
Expenses
Production and mineral taxes		349		453		—		—
Transportation and selling		1,054		832		16		13
Operating		1,605		1,351		62		85
Purchased product		—		—		2,862		4,159
Depreciation, depletion and amortization		3,025		2,688		12		8

Segment Income	$	5,309	$	5,448	$	55	$	2


		Corporate *						Consolidated
		2006			2005			2006			2005

Revenues, Net of Royalties		$	2,050		$	(466	)	$	16,399		$	14,573
Expenses
Production and mineral taxes			—			—			349			453
Transportation and selling			—			—			1,070			845
Operating			(12	)		2			1,655			1,438
Purchased product			—			—			2,862			4,159
Depreciation, depletion and amortization			75			73			3,112			2,769

Segment Income (Loss)		$	1,987		$	(541	)		7,351			4,909

Administrative									271			268
Interest, net									396			524
Accretion of asset retirement obligation									50			37
Foreign exchange (gain) loss, net									14			(24	)
Stock-based compensation — options									—			15
(Gain) on divestitures	(Note 5)								(323	)		—

									408			820

Net Earnings Before Income Tax									6,943			4,089
Income tax expense									1,892			1,260

Net Earnings From Continuing Operations								$	5,051		$	2,829

For the twelve months ended December 31, the pre-tax unrealized gain (loss) on risk management is recorded in the Consolidated Statement of Earnings as follows (see Note 14):


	2006		2005

Revenues, Net of Royalties — Corporate	$	2,050	$	(466	)
Operating Expenses and Other — Corporate		10		(3	)

Total Unrealized Gain (Loss) on Risk Management before-tax — Continuing Operations	$	2,060	$	(469	)


EnCana Corporation		Consolidated Financial Statements (prepared in USS)

Fourth quarter report
for the period ended December 31,2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

3. SEGMENTED INFORMATION (continued)

Results of Continuing Operations (For the twelve months ended December 31)


*Upstream*	Canada				United States
	2006		2005		2006		2005

Revenues, Net of Royalties	$	7,911	$	7,312	$	3,121	$	3,177
Expenses
Production and mineral taxes		116		104		233		349
Transportation and selling		806		650		248		182
Operating		1,029		826		283		212
Depreciation, depletion and amortization		2,142		1,927		848		682

Segment Income	$	3,818	$	3,805	$	1,509	$	1,752

Transportation and selling for the United States includes a one time payment in the first quarter of 2006 of $14 million to terminate a long-term physical delivery contract.


	Other						Total Upstream
	2006			2005			2006		2005

Revenues, Net of Royalties	$	310		$	283		$	11,342	$	10,772
Expenses
Production and mineral taxes		—			—			349		453
Transportation and selling		—			—			1,054		832
Operating		293			313			1,605		1,351
Depreciation, depletion and amortization		35			79			3,025		2,688

Segment Income (Loss)	$	(18	)	$	(109	)	$	5,309	$	5,448

Upstream Geographic and Product Information (Continuing Operations) (For the twelve months ended December 31)


	Produced Gas
	Canada				United States				Total
	2006		2005		2006		2005		2006		2005

Revenues, Net of Royalties	$	5,440	$	5,486	$	2,854	$	2,932	$	8,294	$	8,418
Expenses
Production and mineral taxes		80		76		213		325		293		401
Transportation and selling		278		283		248		182		526		465
Operating		629		521		283		212		912		733

Operating Cash Flow	$	4,453	$	4,606	$	2,110	$	2,213	$	6,563	$	6,819

Transportation and selling for the United States includes a one time payment in the first quarter of 2006 of $14 million to terminate a long-term physical delivery contract.


	Oil & NGLs
	Canada				United States				Total
	2006		2005		2006		2005		2006		2005

Revenues, Net of Royalties	$	2,471	$	1,826	$	267	$	245	$	2,738	$	2,071
Expenses
Production and mineral taxes		36		28		20		24		56		52
Transportation and selling		528		367		—		—		528		367
Operating		400		305		—		—		400		305

Operating Cash Flow	$	1,507	$	1,126	$	247	$	221	$	1,754	$	1,347


	Other					Total Upstream
	2006		2005			2006		2005

Revenues, Net of Royalties	$	310	$	283		$	11,342	$	10,772
Expenses
Production and mineral taxes		—		—			349		453
Transportation and selling		—		—			1,054		832
Operating		293		313			1,605		1,351

Operating Cash Flow	$	17	$	(30	)	$	8,334	$	8,136


EnCana Corporation		Consolidated Financial Statements (prepared in USS)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

3. SEGMENTED INFORMATION (continued)

Capital Expenditures (Continuing Operations)


	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2006		2005		2006		2005

Upstream Core Capital
Canada	$	849	$	1,370	$	4,015	$	4,150
United States		315		633		2,061		1,982
Other Countries		24		31		75		70

		1,188		2,034		6,151		6,202


Upstream Acquisition Capital
Canada		17		4		47		30
United States		16		227		284		418

		33		231		331		448


Market Optimization		4		68		44		197
Corporate		25		29		74		78

Total	$	1,250	$	2,362	$	6,600	$	6,925

Property, Plant and Equipment and Total Assets


		Property, Plant and Equipment				Total Assets
		As at December 31,				As at December 31,
		2006		2005		2006		2005

Upstream		$	27,781	$	24,247	$	32,299	$	28,858
Market Optimization			154		371		469		597
Corporate			278		263		2,338		1,530
Assets of Discontinued Operations	(Note 4)						—		3,163

Total		$	28,213	$	24,881	$	35,106	$	34,148

4. DISCONTINUED OPERATIONS

Midstream

During the fourth quarter of 2005, EnCana decided to divest of its natural gas storage operations. EnCana’s natural gas storage operations included the 100 percent interest in the AECO storage facility as well as facilities in the United States. On March 6, 2006, EnCana announced that it had reached an agreement to sell the gas storage operations for $1.5 billion. The sale, to a single purchaser, which was subject to closing conditions and applicable regulatory approvals closed in two stages. On May 12, 2006, the first stage of the sale was closed for proceeds of $1.3 billion. The second stage closed on November 17, 2006 following receipt of regulatory approvals. A total after-tax gain of $829 million was recorded.

On December 13, 2005, EnCana completed the sale of its Midstream natural gas liquids processing operations for total proceeds of $625 million (C$720 million). The natural gas liquids processing operations included various interests in a number of processing and related facilities as well as a marketing entity. An after-tax gain on sale of approximately $370 million was recorded.

Ecuador

At December 31, 2004, EnCana decided to divest of its Ecuador operations and such operations have been accounted for as discontinued operations. EnCana’s Ecuador operations included the 100 percent working interest in the Tarapoa Block, majority operating interest in Blocks 14, 17 and Shiripuno, the non-operated economic interest in relation to Block 15 and the 36.3 percent indirect equity investment in Oleoducto de Crudos Pesados (OCP) Ltd. (“OCP”), which is the owner of a crude oil pipeline in Ecuador that ships crude oil from the producing areas of Ecuador to an export marine terminal. The Company was a shipper on the OCP Pipeline and paid commercial rates for tariffs. The majority of the Company’s crude oil produced in Ecuador was sold to a single marketing company. Payments were secured by letters of credit from a major financial institution which has a high quality investment grade credit rating.

On February 28, 2006, EnCana completed the sale of its interest in its Ecuador operations for $1.4 billion before indemnifications which are discussed further in this note.

In accordance with Canadian generally accepted accounting principles, depreciation, depletion and amortization expense has not been recorded in the Consolidated Statement of Earnings for discontinued operations.



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

4. DISCONTINUED OPERATIONS (continued)

Consolidated Statement of Earnings

The following table presents the effect of the discontinued operations in the Consolidated Statement of Earnings:


	For the three months ended December 31,
	Ecuador					United Kingdom						Midstream						Total
	2006		2005			2006			2005			2006			2005			2006			2005

Revenues, Net of Royalties	$	—	$	242		$	—		$	—		$	5		$	645		$	5		$	887


Expenses
Production and mineral taxes		—		30			—			—			—			—			—			30
Transportation and selling		—		12			—			—			—			3			—			15
Operating		—		38			—			—			8			110			8			148
Purchased product		—		—			—			—			2			343			2			343
Depreciation, depletion and amortization		—		111			—			—			—			8			—			119
Administration		—		—			—			—			—			30			—			30
Interest, net		—		(2	)		—			—			—			(1	)		—			(3	)
Foreign exchange (gain) loss, net		—		(4	)		(1	)		(37	)		(1	)		—			(2	)		(41	)
(Gain) loss on discontinuance		—		—			—			—			(41	)		(364	)		(41	)		(364	)

		—		185			(1	)		(37	)		(32	)		129			(33	)		277

Net Earnings Before Income Tax		—		57			1			37			37			516			38			610
Income tax expense		—		57			1			4			17			52			18			113

Net Earnings From Discontinued Operations	$	—	$	—		$	—		$	33		$	20		$	464		$	20		$	497


	For the twelve months ended December 31,
	Ecuador						United Kingdom						Midstream						Total
	2006			2005			2006			2005			2006			2005			2006			2005

Revenues, Net of Royalties *	$	200		$	965		$	—		$	—		$	482		$	1,570		$	682		$	2,535


Expenses
Production and mineral taxes		23			131			—			—			—			—			23			131
Transportation and selling		10			58			—			—			—			9			10			67
Operating		25			138			—			—			37			301			62			439
Purchased product		—			—			—			—			356			1,100			356			1,100
Depreciation, depletion and amortization		84			234			—			—			—			28			84			262
Administration		—			—			—			—			—			30			—			30
Interest, net		(2	)		(2	)		—			—			—			(2	)		(2	)		(4	)
Accretion of asset retirement obligation		—			1			—			—			—			—			—			1
Foreign exchange (gain) loss, net		1			(4	)		(1	)		(40	)		4			(2	)		4			(46	)
(Gain) loss on discontinuance		279			—			—			—			(807	)		(364	)		(528	)		(364	)

		420			556			(1	)		(40	)		(410	)		1,100			9			1,616

Net Earnings (Loss) Before Income Tax		(220	)		409			1			40			892			470			673			919
Income tax expense (recovery)		59			278			(4	)		5			17			39			72			322

Net Earnings (Loss) From Discontinued Operations	$	(279	)	$	131		$	5		$	35		$	875		$	431		$	601		$	597


*		Revenues, net of royalties in Ecuador include realized losses of $1 million related to derivative financial instruments. In 2005, revenues, net of royalties included realized losses of $128 million.



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified

4. DISCONTINUED OPERATIONS (continued)

Consolidated Balance Sheet

The impact of the discontinued operations in the Consolidated Balance Sheet is as follows


	As at
	December 31, 2006								December 31, 2005
			United								United
	Ecuador		Kingdom		Midstream		Total		Ecuador		Kingdom			Midstream			Total

Assets
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	207	$	8		$	(7	)	$	208
Accounts receivable and accrued revenues		—		—		—		—		137		—			271			408
Risk management		—		—		—		—		—		—			21			21
Inventories		—		—		—		—		23		—			390			413

		—		—		—		—		367		8			675			1,050
Property, plant and equipment, net		—		—		—		—		1,166		—			520			1,686
Investments and other assets		—		—		—		—		360		—			—			360
Goodwill		—		—		—		—		—		—			67			67

	$	—	$	—	$	—	$	—	$	1,893	$	8		$	1,262		$	3,163

Liabilities
Accounts payable and accrued liabilities	$	—	$	—	$	—	$	—	$	91	$	27		$	49		$	167
Income tax payable		—		—		—		—		184		6			40			230
Risk management		—		—		—		—		—		—			41			41

		—		—		—		—		275		33			130			438
Asset retirement obligation		—		—		—		—		21		—			—			21
Future income taxes (recovery)		—		—		—		—		162		(2	)		86			246

		—		—		—		—		458		31			216			705

Net Assets of Discontinued Operations	$	—	$	—	$	—	$	—	$	1,435	$	(23	)	$	1,046		$	2,458

Contingencies

EnCana agreed to indemnify the purchaser of its Ecuador interests against losses that may arise in certain circumstances which are defined in the share sale agreements. The obligation to indemnify will arise should losses exceed amounts specified in the sale agreements and is limited to maximum amounts which are set forth in the share sale agreements.

During the second quarter of 2006, the Government of Ecuador seized the Block 15 assets, in relation to which EnCana previously held a 40 percent economic interest, from the operator which is an event requiring indemnification under the terms of EnCana’s sale agreement with the purchaser. The purchaser requested payment and EnCana paid the maximum amount in the third quarter, calculated in accordance with the terms of the agreements, of approximately $265 million. EnCana does not expect that any further significant indemnification payments relating to any other business matters addressed in the share sale agreements will be required to be made to the purchaser.

5. DIVESTITURES

Total proceeds received on sale of assets and investments was $689 million (2005 - $2,523 million) as described below:

Upstream

In 2006, the Company has completed the divestiture of mature conventional oil and natural gas assets for proceeds of $78 million (2005 — $471 million).

In August 2006, the Company completed the sale of its 50 percent interest in the Chinook heavy oil discovery offshore Brazil for approximately $367 million which resulted in a gain on sale of $304 million. After recording income tax of $49 million, EnCana recorded an after-tax gain of $255 million.

In May 2005, the Company completed the sale of its Gulf of Mexico assets for approximately $2.1 billion resulting in net proceeds of approximately $1.5 billion after deducting $578 million in tax plus other adjustments. In accordance with full cost accounting for oil and gas activities, proceeds were credited to property, plant and equipment.

Market Optimization

In February 2006, the Company sold its investment in Entrega Gas Pipeline LLC for approximately $244 million which resulted in a gain on sale of $17 million.


EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

6. INTEREST, NET


	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2006			2005				2006			2005

Interest Expense — Long-Term Debt	$	97		$	107			$	366		$	417
Early Retirement of Long-Term Debt		—			—				—			121
Interest Expense — Other		57			6				76			18
Interest Income		(12	)		(9	)			(46	)		(32	)

	$	142		$	104			$	396		$	524

7. FOREIGN EXCHANGE (GAIN) LOSS, NET


	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2006		2005			2006		2005

Unrealized Foreign Exchange (Gain) Loss on Translation of U.S. Dollar Debt Issued from Canada	$	155	$	27		$	—	$	(113	)
Other Foreign Exchange (Gain) Loss		17		10			14		89

	$	172	$	37		$	14	$	(24	)

8. INCOME TAXES

The provision for income taxes is as follows:


	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2006		2005				2006			2005

Current	$	70	$	205			$	764		$	493
Canada
United States		41		(25	)			128			719
Other		2		(2	)			50			(8	)

Total Current Tax		113		178				942			1,204


Future		260		717				1,407			56
Future Tax Rate Reductions		—		—				(457	)		—

	$	373	$	895			$	1,892		$	1,260

Included in current tax for 2006 is $49 million related to the sale of assets in Brazil (2005 – $578 million related to the sale of the Gulf of Mexico assets).

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


	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2006			2005			2006			2005

Net Earnings Before Income Tax	$	1,016		$	2,764		$	6,943		$	4,089
Canadian Statutory Rate		34.7	%		37.9	%		34.7	%		37.9	%

Expected Income Tax		352			1,048			2,407			1,550

Effect on Taxes Resulting from:
Non-deductible Canadian Crown payments		22			68			97			207
Canadian resource allowance		2			(87	)		(16	)		(202	)
Statutory and other rate differences		(18	)		(124	)		(98	)		(235	)
Effect of tax rate changes*		—			—			(457	)		—
Non-taxable capital (gains) losses		29			3			(1	)		(24	)
Tax basis retained on divestitures		—			—			—			(68	)
Large corporations tax		—			1			—			25
Other		(14	)		(14	)		(40	)		7

	$	373		$	895		$	1,892		$	1,260

Effective Tax Rate		36.7	%		32.4	%		27.3	%		30.8	%


*During the second quarter of 2006, the Canadian federal and Alberta governments substantively enacted income tax rate reductions.


EnCana Corporation	Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
All amounts in $ millions unless otherwise specified)

9. LONG-TERM DEBT


	As at			As at
	December 31,			December 31,
	2006			2005

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings	$	1,456		$	1,425
Unsecured notes		793			793

		2,249			2,218


U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings		104			—
Unsecured notes		4,421			4,494

		4,525			4,494


Increase in Value of Debt Acquired *		60			64
Current Portion of Long-Term Debt		(257	)		(73	)

	$	6,577		$	6,703


*		Certain of the notes and debentures of EnCana 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, approximately 21 years.

10. ASSET RETIREMENT OBLIGATION

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties:


	As at			As at
	December 31,			December 31,
	2006			2005

Asset Retirement Obligation, Beginning of Year	$	816		$	611
Liabilities Incurred		68			77
Liabilities Settled		(51	)		(42	)
Liabilities Divested		—			(23	)
Change in Estimated Future Cash Flows		172			135
Accretion Expense		50			37
Other		(4	)		21

Asset Retirement Obligation, End of Year	$	1,051		$	816



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

11. SHARE CAPITAL


	December 31, 2006						December 31, 2005
(millions)	Number			Amount			Number			Amount

Common Shares Outstanding, Beginning of Year		854.9		$	5,131			900.6		$	5,299
Common Shares Issued under Option Plans		8.6			179			15.0			283
Stock-based Compensation		—			11			—			11
Common Shares Purchased		(85.6	)		(734	)		(60.7	)		(462	)

Common Shares Outstanding, End of Year		777.9		$	4,587			854.9		$	5,131

Information related to common shares and stock options has been restated to reflect the effect of the common share split approved in April 2005.

Normal Course Issuer Bid

In 2006, the Company purchased 85.6 million Common Shares for total consideration of approximately $4,219 million. Of the amount paid, $734 million was charged to Share capital and $3,485 million was charged to Retained earnings.

EnCana has received regulatory approval each year under Canadian securities laws to purchase Common Shares under five consecutive Normal Course Issuer Bids (“Bids”). EnCana is entitled to purchase, for cancellation, up to approximately 80.2 million Common Shares under the renewed Bid which commenced on November 6, 2006 and terminates on November 5, 2007.

Stock Options

The Company has stock-based compensation plans that allow employees and directors to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted. Options granted under predecessor and/or related company replacement plans expire up to ten years from the date the options were granted.

The following tables summarize the information about options to purchase Common Shares that do not have Tandem Share Appreciation Rights (“TSAR’s”) attached to them at December 31, 2006. Information related to TSAR’s is included in Note 12.


				Weighted
	Stock			Average
	Options			Exercise
	*(millions)*			Price *(C$)*

Outstanding, Beginning of Year		20.7			23.36
Exercised		(8.6	)		23.60
Forfeited		(0.3	)		23.80

Outstanding, End of Year		11.8			23.17

Exercisable, End of Year		11.8			23.17


	Outstanding Options						Exercisable Options
			Weighted
	Number of		Average		Weighted		Number of		Weighted
	Options		Remaining		Average		Options		Average
	Outstanding		Contractual		Exercise		Outstanding		Exercise
Range of Exercise Price (C$)	(millions)		Life (years)		Price (C$)		(millions)		Price (C$)

11.00 to 16.99		0.8		2.3		11.89		0.8		11.89
17.00 to 22.99		0.2		1.0		22.32		0.2		22.32
23.00 to 23.99		5.4		1.3		23.87		5.4		23.87
24.00 to 24.99		5.2		0.4		24.19		5.2		24.19
25.00 to 25.99		0.2		1.7		25.58		0.2		25.58

		11.8		1.0		23.17		11.8		23.17

At December 31, 2006, the balance in Paid in surplus relates to stock-based compensation programs.



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

12. COMPENSATION PLANS

The tables below outline certain information related to EnCana’s compensation plans at December 31, 2006. Additional information is contained in Note 15 of the Company’s annual audited Consolidated Financial Statements for the year ended December 31, 2005.

A) Pensions

The following table summarizes the net benefit plan expense:


	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2006			2005			2006			2005

Current Service Cost	$	6		$	6		$	16		$	11
Interest Cost		4			6			17			16
Expected Return on Plan Assets		(4	)		(5	)		(16	)		(14	)
Expected Actuarial Loss on Accrued Benefit Obligation		2			3			6			5
Expected Amortization of Past Service Costs		1			1			2			2
Amortization of Transitional Obligation		—			(1	)		(1	)		(2	)
Expense for Defined Contribution Plan		8			6			28			22

Net Benefit Plan Expense	$	17		$	16		$	52		$	40

For the year ended December 31, 2006, contributions of $9 million were made to the defined benefit pension plans.

B) Share Appreciation Rights (“SAR’s”)

The following table summarizes the information about SAR’s at December 31, 2006:


				Weighted
				Average
	Outstanding			Exercise
	SAR’s			Price

Canadian Dollar Denominated *(C$)*
Outstanding, Beginning of Year		246,739			23.13
Exercised		(246,739	)		23.13

Outstanding, End of Year		—			—

Exercisable, End of Year		—			—


U.S. Dollar Denominated *(US$)*
Outstanding, Beginning of Year		319,511			14.33
Exercised		(317,423	)		14.33

Outstanding, End of Year		2,088			14.21

Exercisable, End of Year		2,088			14.21

For the year ended December 31, 2006, EnCana has recorded a reduction in compensation costs of $1 million related to the outstanding SAR’s (2005 — costs of $17 million).



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

12. COMPENSATION PLANS (continued)

C) Tandem Share Appreciation Rights (“TSAR’s”)

The following table summarizes the information about stock options with Tandem SAR’s attached at December 31, 2006:


				Weighted
				Average
	Outstanding			Exercise
	TSAR's			Price

Canadian Dollar Denominated *(C$)*
Outstanding, Beginning of Year		8,403,967			38.41
Granted		11,180,800			49.01
Exercised — SAR’s		(700,418	)		34.54
Exercised — Options		(32,948	)		34.46
Forfeited		(1,575,210	)		43.21

Outstanding, End of Year		17,276,191			44.99

Exercisable, End of Year		1,971,467			38.31

For the year ended December 31, 2006, EnCana recorded compensation costs of $52 million related to the outstanding TSAR’s (2005 — $60 million).

D) Deferred Share Units (“DSU’s”)

The following table summarizes the information about DSU’s at December 31, 2006:


				Average
	Outstanding			Share
	DSU's			Price

Canadian Dollar Denominated *(C$)*
Outstanding, Beginning of Year		836,561			26.81
Granted, Directors		70,000			56.71
Exercised		(52,562	)		27.92
Units, in Lieu of Dividends		12,578			54.69

Outstanding, End of Year		866,577			29.56

Exercisable, End of Year		866,577			29.56

For the year ended December 31, 2006, EnCana recorded compensation costs of $5 million related to the outstanding DSU’s (2005 — $16 million).

E) Performance Share Units (“PSU’s”)

The following table summarizes the information about PSU’s at December 31, 2006:


				Average
	Outstanding			Share
	PSU's			Price

Canadian Dollar Denominated *(C$)*
Outstanding, Beginning of Year		4,704,348			30.65
Granted		36,599			54.82
Paid out		(239,794	)		23.26
Forfeited		(309,313	)		31.35

Outstanding, End of Year		4,191,840			31.24


U.S. Dollar Denominated *(US$)*
Outstanding, Beginning of Year		739,649			25.22
Granted		4,860			48.07
Forfeited		(170,020	)		24.13

Outstanding, End of Year		574,489			25.74

For the year ended December 31, 2006, EnCana recorded compensation costs of $27 million related to the outstanding PSU’s (2005 — $91 million).

At December 31, 2006, EnCana has approximately 5.5 million Common Shares held in trust for issuance upon vesting of the PSU’s (2005 — 5.5 million).



EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31,2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

13. PER SHARE AMOUNTS

The following table summarizes the Common Shares used in calculating Net Earnings per Common Share:


	Three Months Ended										Twelve Months Ended
	March 31,		June 30,		September 30,		December 31,				December 31,
(millions)	2006		2006		2006		2006		2005		2006		2005

Weighted Average Common Shares Outstanding — Basic		847.9		829.6		809.7		792.5		854.4		819.9		868.3
Effect of Dilutive Securities		16.9		15.5		14.6		13.9		18.1		16.6		20.9

Weighted Average Common Shares Outstanding — Diluted		864.8		845.1		824.3		806.4		872.5		836.5		889.2

14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

As a means of managing commodity price volatility, EnCana entered into various financial instrument agreements and physical contracts. The following information presents all positions for financial instruments.

Realized and Unrealized Gain (Loss) on Risk Management Activities

The following tables summarize the gains and losses on risk management activities:


	Realized Gain (Loss)
	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2006		2005			2006		2005

Revenues, Net of Royalties	$	240	$	(355	)	$	393	$	(684	)
Operating Expenses and Other		1		14			5		31

Gain (Loss) on Risk Management — Continuing Operations		241		(341	)		398		(653	)
Gain (Loss) on Risk Management — Discontinued Operations		8		(44	)		12		(155	)

	$	249	$	(385	)	$	410	$	(808	)


	Unrealized Gain (Loss)
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2006			2005			2006		2005

Revenues, Net of Royalties	$	129		$	991		$	2,050	$	(466	)
Operating Expenses and Other		12			(6	)		10		(3	)

Gain (Loss) on Risk Management — Continuing Operations		141			985			2,060		(469	)
Gain (Loss) on Risk Management — Discontinued Operations		(7	)		139			20		50

	$	134		$	1,124		$	2,080	$	(419	)

Amounts Recognized on Transition

Upon initial adoption of the current accounting policy for risk management instruments on January 1, 2004, the fair value of all outstanding financial instruments that were not considered accounting hedges was recorded in the Consolidated Balance Sheet with an offsetting net deferred loss amount (the “transition amount”). The transition amount is recognized into net earnings over the life of the related contracts. Changes in fair value after that time are recorded in the Consolidated Balance Sheet with an associated unrealized gain or loss recorded in net earnings.

At December 31, 2006, a net unrealized gain of approximately $16 million remains to be recognized over the next two years.



EnCana Corporation		Consolidated Financial Statements(prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Fair Value of Outstanding Risk Management Positions

The following table presents a reconciliation of the change in the unrealized amounts from January 1, 2006 to December 31, 2006:


				Total
	Fair Market			Unrealized
	Value			Gain (Loss)

Fair Value of Contracts, Beginning of Year	$	(640	)	$	—
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During 2006		2,466			2,466
Fair Value of Contracts in Place at Transition that Expired During 2006		—			24
Fair Value of Contracts Realized During 2006		(410	)		(410	)

Fair Value of Contracts Outstanding	$	1,416		$	2,080
Unamortized Premiums Paid on Options		104

Fair Value of Contracts and Premiums Paid, End of Year	$	1,520


Amounts Allocated to Continuing Operations	$	1,520		$	2,060
Amounts Allocated to Discontinued Operations		—			20

	$	1,520		$	2,080

At December 31, 2006, the risk management amounts are recorded in the Consolidated Balance Sheet as follows:


	As at
	December 31, 2006

Risk Management
Current asset	$	1,403
Long-term asset		133

Current liability		14
Long-term liability		2

Net Risk Management Asset — Continuing Operations	$	1,520

A summary of all unrealized estimated fair value financial positions is as follows:


	As at
	December 31, 2006

Commodity Price Risk
Natural gas	$	1,431
Crude oil		74
Power		13
Interest Rate Risk		4
Credit Derivatives		(2	)

Total Fair Value Positions	$	1,520

Information with respect to credit derivatives and interest rate risk contracts in place at December 31, 2005 is disclosed in Note 16 to the Company’s annual audited Consolidated Financial Statements. New power contracts have been entered into at December 31, 2006, which are described further in this note.


EnCana Corporation		Consolidated Financial Statements (Prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Natural Gas

At December 31, 2006, the Company’s gas risk management activities from financial contracts had an unrealized gain of $1,410 million and a fair market value position of $1,431 million. The contracts were as follows:


	Notional
	Volumes								Fair Market
	(MMcf/d)		Term		Average Price				Value

Sales Contracts
Fixed Price Contracts

NYMEX Fixed Price		1,487		2007		8.56		US$/Mcf	$	861
Other		8		2007		8.97		US$/Mcf		7
NYMEX Fixed Price		222		2008		8.45		US$/Mcf		34

Options
Purchased NYMEX Put Options		240		2007		6.00		US$/Mcf		15

Basis Contracts
Fixed NYMEX to AECO Basis		747		2007		(0.72	)	US$/Mcf		39
Fixed NYMEX to Rockies Basis		538		2007		(0.65	)	US$/Mcf		223
Fixed NYMEX to CIG Basis		390		2007		(0.76	)	US$/Mcf		144
Fixed Rockies to CIG Basis		12		2007		(0.10	)	US$/Mcf		(1	)

Fixed NYMEX to AECO Basis		191		2008		(0.78	)	US$/Mcf		10
Fixed NYMEX to Rockies Basis		162		2008		(0.59	)	US$/Mcf		46
Fixed NYMEX to CIG Basis		60		2008		(0.67	)	US$/Mcf		15
Fixed NYMEX to Rockies Basis (NYMEX Adjusted)		329		2008	17% of NYMEX			US$/Mcf		14

Fixed NYMEX to Mid-Continent Basis (NYMEX Adjusted)		120		2008	12% of NYMEX			US$/Mcf		4
Fixed NYMEX to CIG Basis		20		2009		(0.71	)	US$/Mcf		1
Fixed NYMEX to AECO Basis		12		2010		(0.40	)	US$/Mcf		—

Purchase Contracts
Fixed Price Contracts
Other		8		2007		7.84		US$/Mcf		(4	)

										1,408
Other Financial Positions^*										2

Total Unrealized Gain on Financial Contracts										1,410
Unamortized Premiums Paid on Options										21

Total Fair Value Positions									$	1,431


*		Other financial positions are part of the ongoing operations of the Company’s proprietary production management.

Crude Oil

At December 31, 2006, the Company’s oil risk management activities from financial contracts had an unrealized loss of $9 million and a fair market value position of $74 million. The contracts were as follows:


	Notional
	Volumes							Fair Market
	(bbls/d)		Term		Average Price			Value

Fixed WTI NYMEX Price		34,500		2007		64.40	US$/bbl	$	(8	)
Purchased WTI NYMEX Put Options		91,500		2007		55.34	US$/bbl		(1	)

									(9	)
Other Financial Positions ^*									—

Total Unrealized Loss on Financial Contracts									(9	)
Unamortized Premiums Paid on Options									83

Total Fair Value Positions								$	74


*		Other financial positions are part of the ongoing operations of the Company’s proprietary production management.

Power

In November 2006, the Company entered into two derivative contracts, commencing January 1, 2007 for a period of eleven years, to manage its electricity consumption costs. At December 31, 2006, these contracts had an unrealized gain of $13 million.


EnCana Corporation		Consolidated Financial Statements (prepared in US$)

Fourth quarter report
for the period ended December 31, 2006

Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)

15. CONTINGENCIES

Legal Proceedings

The Company is involved in various legal claims associated with the normal course of operations. The Company believes it has made adequate provision for such legal claims.

Discontinued Merchant Energy Operations

During the period between 2003 and 2005, EnCana and its indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. (“WD”), along with other energy companies, were named as defendants in several lawsuits, some of which were class action lawsuits, relating to sales of natural gas from 1999 to 2002. The lawsuits allege that the defendants engaged in a conspiracy with unnamed competitors in the natural gas markets in California in violation of U.S. and California anti-trust and unfair competition laws.

Without admitting any liability in the lawsuits, WD agreed to settle all of the class action lawsuits in both state and federal court, for payment, of $20.5 million and $2.4 million, respectively. Court approval of the federal court class action settlement of $2.4 million is pending, court approval having been granted in the state court action. Also, as previously disclosed, without admitting any liability whatsoever, WD concluded settlements with the U.S. Commodity Futures Trading Commission (“CFTC”) and of a previously disclosed consolidated class action lawsuit in the United Stated District Court in New York for $8.2 million.

The remaining lawsuits were commenced by individual plaintiffs, one of which is E. & J. Gallo Winery (“Gallo”). The Gallo lawsuit claims damages in excess of $30 million. The other remaining lawsuits do not specify the precise amount of damages claimed. California law allows for the possibility that the amount of damages assessed could be tripled.

The Company and WD intend to vigorously defend against the outstanding claims; however, the Company cannot predict the outcome of these proceedings or any future proceedings against the Company, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Company’s financial position, or whether there will be other proceedings arising out of these allegations.

16. SUBSEQUENT EVENTS

Integrated Oilsands Business

On January 2, 2007, EnCana became a 50 percent partner in an integrated, North American heavy oil business with ConocoPhillips which consists of an upstream and a downstream entity. In creating the integrated venture, EnCana contributed 50 percent of its Foster Creek and Christina Lake oilsands properties while ConocoPhillips contributed 50 percent of its Wood River and Borger refineries, located in Illinois and Texas respectively. On a go forward basis, EnCana will show a separate business segment for the Integrated Oilsands business. In accordance with the Canadian generally accepted accounting principles, these entities will be accounted for using the proportionate consolidation method.

Sale of Chad Operations

On January 12, 2007, EnCana announced that it had completed the sale of its interests in Chad, properties that are considered to be in the pre-production stage, for proceeds of $203 million which will result in a gain on sale.

The Bow

On February 9, 2007, EnCana announced that it had completed the next phase in the development of The Bow office project with the sale of project assets and is entering into a 25 year lease agreement with a third party developer. EnCana expects to account for the agreement as a capital lease.


EnCana Corporation		Consolidated Financial Statements (prepared in US$)