Edgar Filing: ENCANA CORP

Form 6-K

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Report of Foreign Private Issuer

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


For the quarterly period ended September 30, 2004		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 [ ] 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): [ ]

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 [ ] No [ü]

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

Exhibits 1 and 2 to this report, furnished on Form 6-K, shall be incorporated by reference into each of the Registration Statements under the Securities Act of 1933 of the registrant:

Form S-8 No. 333-13956; Form S-8 No. 333-85598; Form F-9 No. 333-113732; and Form F-9 No. 333-118737.

TABLE OF CONTENTS


SIGNATURES
Unaudited Interim Consolidated Financial Statements
Management's Discussion and Analysis
Covering letter dated October 27, 2004
Comfort Letter, dated October 27, 2004
Supplemental Financial Information (Unaudited)
Certificate, dated October 26, 2004, of Gwyn Morgan
Certificate, dated October 26, 2004, of John D. Watson

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: October 27, 2004


				ENCANA CORPORATION
				(Registrant)

		By:		/s/ Linda H. Mackid

				Name: Linda H. Mackid
				Title: Assistant Corporate Secretary

Form 6-K Exhibit Index


Exhibit No.
		The following documents have been filed with Canadian securities commissions and with each of the Toronto Stock Exchange (via SEDAR) and the New York Stock Exchange (via EDGAR):

1.		Unaudited Interim Consolidated Financial Statements for the period ended September 30, 2004.

2.		Management’s Discussion and Analysis dated October 26, 2004 relating to the period ended September 30, 2004.

		In addition, we attach, among other documents, the comfort letter of our auditors, PricewaterhouseCoopers LLP, in relation to the aforesaid documents and the Consolidated Financial Ratios, which were filed with the unaudited Interim Consolidated Financial Statements for the period ended September 30, 2004. These documents have been filed with the various Canadian securities commissions.

3.		Covering letter dated October 27, 2004 regarding Financial Ratios and the Auditor Comfort Letter.

4.		Comfort Letter, dated October 27 2004, of PricewaterhouseCoopers LLP.

5.		Supplemental Financial Information (Unaudited) Exhibit to September 30, 2004 Consolidated Financial Statements “Consolidated Financial Ratios – Medium Term Notes & Debt Securities”.

6.		Certificate, dated October 26, 2004, of Gwyn Morgan, President & Chief Executive Officer, regarding the “Certification of Interim Filings during Transition Period” pursuant to Form 52-109FT2.

7.		Certificate, dated October 26, 2004, of John D. Watson, Executive Vice-President & Chief Financial Officer, regarding the “Certification of Interim Filings during Transition Period” pursuant to Form 52-109FT2.

Interim Consolidated Financial Statements
(unaudited)
For the period ended September 30, 2004

EnCana Corporation

U.S. DOLLARS


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

CONSOLIDATED STATEMENT OF EARNINGS (unaudited)


		September 30
		Three Months Ended						Nine Months Ended
(US$ millions, except per share amounts)		2004			2003			2004			2003
REVENUES, NET OF ROYALTIES	(Note 5)
Upstream		$	2,070		$	1,509		$	5,853		$	4,651
Midstream & Marketing			889			781			3,206			2,713
Corporate			(501	)		1			(1,033	)		2

			2,458			2,291			8,026			7,366
EXPENSES	(Note 5)
Production and mineral taxes			97			33			258			131
Transportation and selling			144			125			468			375
Operating			382			322			1,081			960
Purchased product			800			692			2,909			2,406
Depreciation, depletion and amortization			694			525			2,051			1,497
Administrative			43			41			136			121
Interest, net			103			71			278			202
Accretion of asset retirement obligation	(Note 10)		8			5			20			15
Foreign exchange (gain)	(Note 7)		(288	)		(20	)		(209	)		(436	)
Stock-based compensation			5			6			14			12
Gain on dispositions	(Note 4)		—			—			(35	)		—

			1,988			1,800			6,971			5,283

NET EARNINGS BEFORE INCOME TAX			470			491			1,055			2,083
Income tax expense	(Note 8)		77			205			122			342

NET EARNINGS FROM CONTINUING OPERATIONS			393			286			933			1,741
NET EARNINGS FROM DISCONTINUED OPERATIONS	(Note 6)		—			4			—			193

NET EARNINGS		$	393		$	290		$	933		$	1,934

NET EARNINGS FROM CONTINUING OPERATIONS PER COMMON SHARE	(Note 13)
Basic		$	0.85		$	0.60		$	2.02		$	3.64
Diluted		$	0.84		$	0.60		$	2.00		$	3.60

NET EARNINGS PER COMMON SHARE	(Note 13)
Basic		$	0.85		$	0.61		$	2.02		$	4.05
Diluted		$	0.84		$	0.61		$	2.00		$	4.00

CONSOLIDATED STATEMENT OF RETAINED EARNINGS


		Nine Months Ended
		September 30,
(US$ millions)		2004			2003
RETAINED EARNINGS, BEGINNING OF YEAR
As previously reported		$	5,276		$	3,457
Retroactive adjustment for changes in accounting policies			—			66

As restated			5,276			3,523
Net Earnings			933			1,934
Dividends on Common Shares			(137	)		(103	)
Charges for Normal Course Issuer Bid	(Note 11)		(126	)		(360	)

RETAINED EARNINGS, END OF PERIOD		$	5,946		$	4,994

See accompanying Notes to Consolidated Financial Statements.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

CONSOLIDATED BALANCE SHEET (unaudited)

As at

September 30,

December 31,

(US$ millions)

2004

2003

ASSETS

Current Assets

Cash and cash equivalents

107

148

Accounts receivable and accrued revenues

2,066

1,367

Risk management

(Note 14)

—

Inventories

700

573

2,957

2,088

Property, Plant and Equipment, net

(Note 5)

23,623

19,545

Investments and Other Assets

637

566

Risk Management

(Note 14)

—

Goodwill

2,410

1,911

(Note 5)

29,673

24,110

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities

Accounts payable and accrued liabilities

2,059

1,579

Risk management

(Note 14)

800

—

Income tax payable

526

Current portion of long-term debt

(Note 9)

550

287

3,935

1,931

Long-Term Debt

(Note 9)

8,036

6,088

Other Liabilities

Risk Management

(Note 14)

332

—

Asset Retirement Obligation

(Note 10)

490

430

Future Income Taxes

4,712

4,362

17,590

12,832

Shareholders’ Equity

Share capital

(Note 11)

5,412

5,305

Share options, net

Paid in surplus

Retained earnings

5,946

5,276

Foreign currency translation adjustment

651

624

12,083

11,278

29,673

24,110

See accompanying Notes to Consolidated Financial Statements.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)


		September 30
		Three Months Ended						Nine Months Ended
(US$ millions)		2004			2003			2004			2003
OPERATING ACTIVITIES
Net earnings from continuing operations		$	393		$	286		$	933		$	1,741
Depreciation, depletion and amortization			694			525			2,051			1,497
Future income taxes	(Note 8)		(47	)		154			(437	)		325
Unrealized loss on risk management	(Note 14)		497			—			1,028			—
Unrealized foreign exchange (gain)	(Note 7)		(193	)		(15	)		(122	)		(404	)
Accretion of asset retirement obligation	(Note 10)		8			5			20			15
Gain on dispositions	(Note 4)		—			—			(35	)		—
Other			11			18			51			29

Cash flow from continuing operations			1,363			973			3,489			3,203
Cash flow from discontinued operations			—			4			—			2

Cash flow			1,363			977			3,489			3,205
Net change in other assets and liabilities			(25	)		(111	)		(71	)		(82	)
Net change in non-cash working capital from continuing operations			(276	)		159			(103	)		200
Net change in non-cash working capital from discontinued operations			—			(3	)		—			54

			1,062			1,022			3,315			3,377

INVESTING ACTIVITIES
Business combination with Tom Brown, Inc.	(Note 3)		—			—			(2,335	)		—
Capital expenditures	(Note 5)		(1,147	)		(1,345	)		(3,892	)		(3,438	)
Proceeds on disposal of assets			941			—			1,072			19
Dispositions (acquisitions)	(Note 4)		(1	)		(91	)		287			(207	)
Equity investments	(Note 4)		8			(25	)		52			(158	)
Net change in investments and other			(46	)		(41	)		(68	)		(68	)
Net change in non-cash working capital from continuing operations			(24	)		46			(70	)		(112	)
Discontinued operations			—			307			—			1,585

			(269	)		(1,149	)		(4,954	)		(2,379	)

FINANCING ACTIVITIES
Net (repayment) issuance of revolving long-term debt			(662	)		722			(215	)		262
Issuance of long-term debt			1,000			—			3,761			—
Repayment of long-term debt			(1,205	)		(71	)		(1,754	)		(142	)
Issuance of common shares	(Note 11)		30			12			184			95
Purchase of common shares	(Note 11)		—			(560	)		(230	)		(682	)
Dividends on common shares			(45	)		(35	)		(137	)		(103	)
Other			(6	)		8			(11	)		(5	)
Discontinued operations			—			—			—			(282	)

			(888	)		76			1,598			(857	)

DEDUCT: FOREIGN EXCHANGE LOSS ON CASH AND CASH EQUIVALENTS HELD IN FOREIGN CURRENCY			—			1			—			9

(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS			(95	)		(52	)		(41	)		132
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			202			300			148			116

CASH AND CASH EQUIVALENTS, END OF PERIOD		$	107		$	248		$	107		$	248

See accompanying Notes to Consolidated Financial Statements.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)

(All amounts in US$ millions unless otherwise specified)

1. BASIS OF PRESENTATION

The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries (the “Company”), and are presented in accordance with Canadian generally accepted accounting principles. The Company is in the business of exploration for, and production and marketing of, natural gas, natural gas liquids and crude oil, as well as natural gas storage operations, natural gas liquids processing 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, 2003, 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, 2003.

2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES

Hedging Relationships

On January 1, 2004, the Company adopted the amendments made to Accounting Guideline 13 (“AcG - 13”) “Hedging Relationships”, and EIC 128, “Accounting for Trading, Speculative or Non Trading Derivative Financial Instruments”. Derivative instruments that do not qualify as a hedge under AcG - 13, or are not designated as a hedge, are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. The Company has elected not to designate any of its price risk management activities in place at September 30, 2004 as accounting hedges under AcG - 13 and, accordingly, will account for all these non-hedging derivatives using the mark-to-market accounting method. The impact on the Company’s Consolidated Financial Statements at January 1, 2004 resulted in the recognition of risk management assets with a fair value of $145 million, risk management liabilities with a fair value of $380 million and a net deferred loss of $235 million which will be recognized into net earnings as the contracts expire. At September 30, 2004, it is estimated that over the following 12 months, $42 million ($30 million, net of tax) will be reclassified into net earnings from net deferred losses.

The following table presents the deferred amounts expected to be recognized in net earnings as unrealized gains/(losses) over the years 2004 to 2008:


	Unrealized
	Gain/(Loss)
2004
Quarter 4	$	(64	)

Total remaining to be recognized in 2004	$	(64	)

2005
Quarter 1	$	—
Quarter 2		13
Quarter 3		9
Quarter 4		9

Total to be recognized in 2005	$	31

2006		24
2007		15
2008		1

Total to be recognized in 2006 to 2008	$	40

Total to be recognized	$	7

At September 30, 2004, the remaining net deferred loss totalled $7 million of which $72 million was recorded in Accounts receivable and accrued revenues, $3 million in Investments and other assets, $30 million in Accounts payable and accrued liabilities and $52 million in Other liabilities.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

3. BUSINESS COMBINATION WITH TOM BROWN, INC.

In May 2004, the Company completed the tender offer for the common shares of Tom Brown, Inc., a Denver based independent energy company for total cash consideration of $2.3 billion.

The business combination has been accounted for using the purchase method with results of operations of Tom Brown, Inc. included in the Consolidated Financial Statements from the date of acquisition.

The calculation of the purchase price and the preliminary allocation to assets and liabilities is shown below. The purchase price and goodwill allocation is preliminary because certain items such as determination of the final tax bases and fair values of the assets and liabilities as of the acquisition date have not been completed.


Calculation of Purchase Price
Cash paid for common shares of Tom Brown, Inc.	$	2,341
Transaction costs		13

Total purchase price	$	2,354
Plus: Fair value of liabilities assumed
Current liabilities		276
Long-term debt		406
Other non-current liabilities		39
Future income taxes		710

Total Purchase Price and Liabilities Assumed	$	3,785

Fair Value of Assets Acquired
Current assets (including cash acquired of $19 million)	$	440
Property, plant, and equipment		2,879
Other non-current assets		9
Goodwill		457

Total Fair Value of Assets Acquired	$	3,785

Included in current assets as Assets held for sale is $278 million related to the value of certain oil and gas properties located in west Texas and southwestern New Mexico and the assets of Sauer Drilling Company, a subsidiary of Tom Brown, Inc., which the Company has entered into purchase and sale agreements. These sales were completed on July 30, 2004.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

4. DISPOSITIONS (ACQUISITIONS)

In March 2004, the Company sold its investment in a well servicing company for approximately $44 million, recording a gain on sale of $34 million.

On February 18, 2004, the Company sold its 53.3 percent interest in Petrovera Resources (“Petrovera”) for approximately $287 million, including working capital adjustments. In order to facilitate the transaction, EnCana purchased the 46.7 percent interest of its partner for approximately $253 million, including working capital adjustments, and then sold the 100 percent interest in Petrovera for a total of approximately $540 million, including working capital adjustments. There was no gain or loss recorded on this sale.

On January 31, 2003, the Company acquired the Ecuadorian interests of Vintage Petroleum Inc. (“Vintage”) for net cash consideration of $116 million. On July 18, 2003, the Company acquired the common shares of Savannah Energy Inc. (“Savannah”) for net cash consideration of $91 million. Savannah’s operations are in Texas, USA. These purchases were accounted for using the purchase method with the results reflected in the consolidated results of EnCana from the dates of acquisition.

Other dispositions of discontinued operations are disclosed in Note 6.

5. 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, natural gas liquids and crude oil and other related activities. The majority of the Company’s Upstream operations are located in Canada, the United States, the United Kingdom and Ecuador. International new venture exploration is mainly focused on opportunities in Africa, South America and the Middle East.

•		Midstream & Marketing includes natural gas storage operations, natural gas liquids processing and power generation operations, as well as marketing activities. These marketing activities include the sale and delivery of produced product and the purchasing of third party product primarily for the optimization of midstream assets, as well as the optimization of transportation arrangements not fully utilized for the Company’s own production.

•		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.

Midstream & Marketing purchases all of the Company’s North American Upstream production. 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 6.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

5. SEGMENTED INFORMATION (continued)

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


	Upstream				Midstream & Marketing
	2004		2003		2004		2003
Revenues, Net of Royalties	$	2,070	$	1,509	$	889	$	781
Expenses
Production and mineral taxes		97		33		—		—
Transportation and selling		140		114		4		11
Operating		304		258		77		64
Purchased product		—		—		800		692
Depreciation, depletion and amortization		672		502		8		9

Segment Income	$	857	$	602	$	—	$	5


	Corporate						Consolidated
	2004			2003			2004			2003
Revenues, Net of Royalties *	$	(501	)	$	1		$	2,458		$	2,291
Expenses
Production and mineral taxes		—			—			97			33
Transportation and selling		—			—			144			125
Operating		1			—			382			322
Purchased product		—			—			800			692
Depreciation, depletion and amortization		14			14			694			525

Segment Income	$	(516	)	$	(13	)		341			594

Administrative								43			41
Interest, net								103			71
Accretion of asset retirement obligation								8			5
Foreign exchange (gain)								(288	)		(20	)
Stock-based compensation								5			6
Gain on dispositions								—			—

								(129	)		103

Net Earnings Before Income Tax								470			491
Income tax expense								77			205

Net Earnings from Continuing Operations							$	393		$	286

* Corporate revenue primarily reflects unrealized gains or losses recorded on derivative instruments. See also Note 14.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

5. SEGMENTED INFORMATION (continued)

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


Upstream	Canada				United States				Ecuador
	2004		2003		2004		2003		2004		2003
Revenues, Net of Royalties	$	1,283	$	1,072	$	512	$	281	$	159	$	81
Expenses
Production and mineral taxes		23		4		56		28		18		1
Transportation and selling		91		80		23		22		16		9
Operating		170		170		32		18		30		16
Depreciation, depletion and amortization		445		377		131		78		63		33

Segment Income	$	554	$	441	$	270	$	135	$	32	$	22


	U.K. North Sea					Other					Total Upstream
	2004		2003			2004			2003		2004		2003
Revenues, Net of Royalties	$	50	$	17		$	66		$	58	$	2,070	$	1,509
Expenses
Production and mineral taxes		—		—			—			—		97		33
Transportation and selling		10		3			—			—		140		114
Operating		12		3			60			51		304		258
Depreciation, depletion and amortization		26		12			7			2		672		502

Segment Income	$	2	$	(1	)	$	(1	)	$	5	$	857	$	602


										Total Midstream
Midstream & Marketing	Midstream					Marketing				& Marketing
	2004			2003		2004		2003		2004		2003
Revenues	$	158		$	180	$	731	$	601	$	889	$	781
Expenses
Transportation and selling		—			—		4		11		4		11
Operating		65			57		12		7		77		64
Purchased product		88			112		712		580		800		692
Depreciation, depletion and amortization		8			7		—		2		8		9

Segment Income	$	(3	)	$	4	$	3	$	1	$	—	$	5


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

5. SEGMENTED INFORMATION (continued)

Upstream Geographic and Product Information (For the three months ended September 30)


Produced Gas	Produced Gas
	Canada				United States				U.K. North Sea				Total
	2004		2003		2004		2003		2004		2003		2004		2003
Revenues, Net of Royalties	$	970	$	806	$	462	$	259	$	10	$	2	$	1,442	$	1,067
Expenses
Production and mineral taxes		18		15		51		25		—		—		69		40
Transportation and selling		72		71		23		22		7		1		102		94
Operating		99		89		32		18		—		—		131		107

Operating Cash Flow	$	781	$	631	$	356	$	194	$	3	$	1	$	1,140	$	826


Oil & NGLs	Oil & NGLs
	Canada					United States				Ecuador
	2004		2003			2004		2003		2004		2003
Revenues, Net of Royalties	$	313	$	266		$	50	$	22	$	159	$	81
Expenses
Production and mineral taxes		5		(11	)		5		3		18		1
Transportation and selling		19		9			—		—		16		9
Operating		71		81			—		—		30		16

Operating Cash Flow	$	218	$	187		$	45	$	19	$	95	$	55


	Oil & NGLs
	U.K. North Sea				Total
	2004		2003		2004		2003
Revenues, Net of Royalties	$	40	$	15	$	562	$	384
Expenses
Production and mineral taxes		—		—		28		(7	)
Transportation and selling		3		2		38		20
Operating		12		3		113		100

Operating Cash Flow	$	25	$	10	$	383	$	271


Other & Total Upstream	Other				Total Upstream
	2004		2003		2004		2003
Revenues, Net of Royalties	$	66	$	58	$	2,070	$	1,509
Expenses
Production and mineral taxes		—		—		97		33
Transportation and selling		—		—		140		114
Operating		60		51		304		258

Operating Cash Flow	$	6	$	7	$	1,529	$	1,104


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

5. SEGMENTED INFORMATION (continued)

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


	Upstream				Midstream & Marketing
	2004		2003		2004			2003
Revenues, Net of Royalties	$	5,853	$	4,651	$	3,206		$	2,713
Expenses
Production and mineral taxes		258		131		—			—
Transportation and selling		448		331		20			44
Operating		861		719		224			241
Purchased product		—		—		2,909			2,406
Depreciation, depletion and amortization		1,947		1,444		60			21

Segment Income	$	2,339	$	2,026	$	(7	)	$	1


	Corporate						Consolidated
	2004			2003			2004			2003
Revenues, Net of Royalties *	$	(1,033	)	$	2		$	8,026		$	7,366
Expenses
Production and mineral taxes		—			—			258			131
Transportation and selling		—			—			468			375
Operating		(4	)		—			1,081			960
Purchased product		—			—			2,909			2,406
Depreciation, depletion and amortization		44			32			2,051			1,497

Segment Income	$	(1,073	)	$	(30	)		1,259			1,997

Administrative								136			121
Interest, net								278			202
Accretion of asset retirement obligation								20			15
Foreign exchange (gain)								(209	)		(436	)
Stock-based compensation								14			12
Gain on dispositions								(35	)		—

								204			(86	)

Net Earnings Before Income Tax								1,055			2,083
Income tax expense								122			342

Net Earnings from Continuing Operations							$	933		$	1,741

* Corporate revenue primarily reflects unrealized gains or losses recorded on derivative instruments. See also Note 14.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

5. SEGMENTED INFORMATION (continued)

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


Upstream	Canada				United States				Ecuador
	2004		2003		2004		2003		2004		2003
Revenues, Net of Royalties	$	3,770	$	3,343	$	1,313	$	845	$	432	$	243
Expenses
Production and mineral taxes		61		33		155		81		42		17
Transportation and selling		277		241		93		56		49		24
Operating		505		482		80		43		89		50
Depreciation, depletion and amortization		1,296		1,089		330		211		197		87

Segment Income	$	1,631	$	1,498	$	655	$	454	$	55	$	65

Transportation and selling for the United States includes a one-time payment of $21 million made in Q2 2004 to terminate a long-term physical delivery contract.


	U.K. North Sea				Other					Total Upstream
	2004		2003		2004			2003		2004		2003
Revenues, Net of Royalties	$	168	$	73	$	170		$	147	$	5,853	$	4,651
Expenses
Production and mineral taxes		—		—		—			—		258		131
Transportation and selling		29		10		—			—		448		331
Operating		32		10		155			134		861		719
Depreciation, depletion and amortization		93		53		31			4		1,947		1,444

Segment Income	$	14	$	—	$	(16	)	$	9	$	2,339	$	2,026


											Total Midstream
Midstream & Marketing	Midstream					Marketing					& Marketing
	2004			2003		2004		2003			2004			2003
Revenues	$	881		$	649	$	2,325	$	2,064		$	3,206		$	2,713
Expenses
Transportation and selling		—			—		20		44			20			44
Operating		192			188		32		53			224			241
Purchased product		655			423		2,254		1,983			2,909			2,406
Depreciation, depletion and amortization		58			18		2		3			60			21

Segment Income	$	(24	)	$	20	$	17	$	(19	)	$	(7	)	$	1

Midstream Depreciation, depletion and amortization includes a $35 million impairment charge made in Q2 2004 on the Company’s interest in Oleoducto Trasandino in Argentina and Chile.


Interim Report		PREPARED IN US$
For the period ended September 30, 2004

EnCana Corporation

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

5. SEGMENTED INFORMATION (continued)

Upstream Geographic and Product Information (For the nine months ended September 30)


	Produced Gas
	Canada				United States				U.K. North Sea				Total
Produced Gas	2004		2003		2004		2003		2004		2003		2004		2003
Revenues, Net of Royalties	$	2,887	$	2,534	$	1,198	$	776	$	36	$	8	$	4,121	$	3,318
Expenses
Production and mineral taxes		46		33		142		77		—		—		188		110
Transportation and selling		222		193		93		56		19		6		334		255
Operating		297		258		80		43		—		—		377		301

Operating Cash Flow	$	2,322	$	2,050	$	883	$	600	$	17	$	2	$	3,222	$	2,652

Transportation and selling for the United States includes a one-time payment of $21 million made in Q2 2004 to terminate a long-term physical delivery contract.


	Oil & NGLs
	Canada				United States				Ecuador
Oil & NGLs	2004		2003		2004		2003		2004		2003
Revenues, Net of Royalties	$	883	$	809	$	115	$	69	$	432	$	243
Expenses
Production and mineral taxes		15		—		13		4		42		17
Transportation and selling		55		48		—		—		49		24
Operating		208		224		—		—		89		50

Operating Cash Flow	$	605	$	537	$	102	$	65	$	252	$	152


	Oil & NGLs
	U.K. North Sea				Total
	2004		2003		2004		2003
Revenues, Net of Royalties	$	132	$	65	$	1,562	$	1,186
Expenses
Production and mineral taxes		—		—		70		21
Transportation and selling		10		4		114		76
Operating		32		10		329		284

Operating Cash Flow	$	90	$	51	$	1,049	$	805


	Other				Total Upstream
Other & Total Upstream	2004		2003		2004		2003
Revenues, Net of Royalties	$	170	$	147	$	5,853	$	4,651
Expenses
Production and mineral taxes		—		—		258		131
Transportation and selling		—		—		448		331
Operating		155		134		861		719

Operating Cash Flow	$	15	$	13	$	4,286	$	3,470


Interim Report		PREPARED IN US$
For the period ended September 30, 2004

EnCana Corporation

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

5. SEGMENTED INFORMATION (continued)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Capital Expenditures	2004		2003		2004		2003
Upstream
Canada	$	634	$	901	$	2,337	$	2,287
United States		328		280		854		626
Ecuador		53		65		163		172
United Kingdom		92		19		421		45
Other Countries		15		15		49		63

		1,122		1,280		3,824		3,193
Midstream & Marketing		15		58		40		207
Corporate		10		7		28		38

Total	$	1,147	$	1,345	$	3,892	$	3,438

Property, Plant and Equipment

Total Assets

As at

September 30,

December 31,

September 30,

December 31,

Property, Plant and Equipment and Total Assets

2004

2003

2004

2003

Upstream

22,590

18,532

27,030

21,742

Midstream & Marketing

808

784

1,977

1,879

Corporate

225

229

666

489

Total

23,623

19,545

29,673

24,110


Interim Report		PREPARED IN US$
For the period ended September 30, 2004

EnCana Corporation

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

6. DISCONTINUED OPERATIONS

On February 28, 2003, the Company completed the sale of its 10 percent working interest in the Syncrude Joint Venture (“Syncrude”) to Canadian Oil Sands Limited for net cash consideration of C$1,026 million ($690 million). On July 10, 2003, the Company completed the sale of the remaining 3.75 percent interest in Syncrude and a gross overriding royalty for net cash consideration of C$427 million ($309 million). There was no gain or loss on this sale.

On January 2, 2003 and January 9, 2003, the Company completed the sales of its interests in the Cold Lake Pipeline System and Express Pipeline System for total consideration of approximately C$1.6 billion ($1 billion), including assumption of related long-term debt by the purchaser, and recorded an after-tax gain on sale of C$263 million ($169 million).

As all discontinued operations have either been disposed of or wind up has been completed by December 31, 2003, there are no remaining assets or liabilities on the Consolidated Balance Sheet. The following tables present the effect of the discontinued operations on the Consolidated Statement of Earnings for 2003:

Consolidated Statement of Earnings


	For the three months ended
	September 30, 2003
				Midstream -
	Syncrude			Pipelines		Total
Revenues, Net of Royalties	$	8		$	—	$	8

Expenses
Transportation and selling		—			—		—
Operating		4			—		4
Depreciation, depletion and amortization		1			—		1
Gain on discontinuance		—			—		—

		5			—		5

Net Earnings Before Income Tax		3			—		3
Income tax expense		(1	)		—		(1	)

Net Earnings from Discontinued Operations	$	4		$	—	$	4

Consolidated Statement of Earnings


	For the nine months ended
	September 30, 2003
			Midstream -
	Syncrude		Pipelines			Total
Revenues, Net of Royalties	$	87	$	—		$	87

Expenses
Transportation and selling		2		—			2
Operating		46		—			46
Depreciation, depletion and amortization		7		—			7
Gain on discontinuance		—		(220	)		(220	)

		55		(220	)		(165	)

Net Earnings Before Income Tax		32		220			252
Income tax expense		8		51			59

Net Earnings from Discontinued Operations	$	24	$	169		$	193


Interim Report		PREPARED IN US$
For the period ended September 30, 2004

EnCana Corporation

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

7. FOREIGN EXCHANGE (GAIN)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Unrealized Foreign Exchange (Gain) on Translation of U.S. Dollar Debt Issued in Canada	$	(193	)	$	(15	)	$	(122	)	$	(404	)
Realized Foreign Exchange (Gain)		(95	)		(5	)		(87	)		(32	)

	$	(288	)	$	(20	)	$	(209	)	$	(436	)

8. INCOME TAXES

The provision for income taxes is as follows:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2004			2003		2004			2003
Current
Canada	$	76		$	31	$	441		$	(18	)
United States		3			10		18			10
Ecuador		44			8		98			21
United Kingdom		—			1		—			3
Other		1			1		2			1

Total Current Tax		124			51		559			17
Future		(47	)		154		(328	)		687
Future Tax Rate Reductions *		—			—		(109	)		(362	)

Total Future Tax		(47	)		154		(437	)		325

	$	77		$	205	$	122		$	342

* On March 31, 2004, the Alberta government substantively enacted the income tax rate reduction previously announced in February 2004.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Net Earnings Before Income Tax	$	470		$	491		$	1,055		$	2,083
Canadian Statutory Rate		39.1	%		41.0	%		39.1	%		41.0	%

Expected Income Taxes		184			201			413			853
Effect on Taxes Resulting from:
Non-deductible Canadian crown payments		51			44			154			176
Canadian resource allowance		(57	)		(56	)		(173	)		(206	)
Canadian resource allowance on unrealized risk management losses		13			—			40			—
Statutory and other rate differences		(19	)		1			(49	)		(23	)
Effect of tax rate changes		—			—			(109	)		(362	)
Non-taxable capital gains		(55	)		(1	)		(41	)		(71	)
Previously unrecognized capital losses		(5	)		(71	)		10			(71	)
Tax basis retained on dispositions		(59	)		—			(162	)		—
Large corporations tax		6			8			13			25
Other		18			79			26			21

	$	77		$	205		$	122		$	342

Effective Tax Rate		16.4	%		41.8	%		11.6	%		16.4	%


Interim Report		PREPARED IN US$
For the period ended September 30, 2004

EnCana Corporation

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

9. LONG-TERM DEBT


	As at			As at
	September 30,			December 31,
	2004			2003
Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings	$	1,509		$	1,425
Unsecured notes and debentures		1,325			1,335
Preferred securities		—			252

		2,834			3,012

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings		965			417
Unsecured notes and debentures		4,716			2,713
Preferred securities		—			150

		5,681			3,280

Increase in Value of Debt Acquired *		71			83
Current Portion of Long-Term Debt		(550	)		(287	)

	$	8,036		$	6,088

* 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, approximately 22 years.

To fund the acquisition of Tom Brown, Inc., the Company arranged a $3 billion non-revolving term loan facility with a group of the Company’s lenders. The facility size has been reduced to an outstanding amount of $846 million as at September 30, 2004. The remaining facility amount is to be reduced to $450 million by August 20, 2005 and to zero on May 20, 2006.

During the quarter, the Company completed an issue of notes under its shelf prospectus. The US$250 million notes are due in 2009 and bear interest at 4.60%. The US$750 million notes are due in 2034 and bear interest at 6.50%. The proceeds from the note issue were used to repay bank and commercial paper indebtedness. In addition, the Company also redeemed, at par value, the C$200 million 8.50% Preferred Securities and the US$150 million 9.50% Preferred Securities.

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
	September 30,			December 31,
	2004			2003
Asset Retirement Obligation, Beginning of Year	$	430		$	309
Liabilities Incurred		64			64
Liabilities Settled		(9	)		(23	)
Liabilities Disposed		(35	)		—
Accretion Expense		20			19
Other		20			61

Asset Retirement Obligation, End of Period	$	490		$	430


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

11. SHARE CAPITAL


	September 30, 2004						December 31, 2003
(millions)	Number			Amount			Number			Amount
Common Shares Outstanding, Beginning of Year		460.6		$	5,305			478.9		$	5,511
Shares Issued under Option Plans		6.9			184			5.5			114
Shares Repurchased		(5.5	)		(77	)		(23.8	)		(320	)

Common Shares Outstanding, End of Period		462.0		$	5,412			460.6		$	5,305

To September 30, 2004, the Company purchased, for cancellation, 5,490,000 Common Shares for total consideration of approximately C$304 million ($230 million). Of the amount paid, C$101 million ($77 million) was charged to Share capital, C$36 million ($27 million) was charged to Paid in surplus and C$167 million ($126 million) was charged to Retained earnings.

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 grant date. Options granted under previous successor and/or related company replacement plans expire ten years from the date the options were granted.

The following tables summarize the information about options to purchase Common Shares at September 30, 2004:


				Weighted Average
	Stock Options			Exercise Price
	(millions)			(C$)
Outstanding, Beginning of Year		28.8			43.13
Exercised		(6.9	)		35.46
Forfeited		(0.6	)		47.30

Outstanding, End of Period		21.3			45.42

Exercisable, End of Period		13.4			43.90


	Outstanding Options						Exercisable Options
	Number of Options		Weighted Average Remaining		Weighted Average Exercise		Number of Options Outstanding		Weighted Average
Range of Exercise Price (C$)	Outstanding (millions)		Contractual Life (years)		Price (C$)		(millions)		Exercise Price (C$)
13.50 to 19.99		0.4		0.6		18.62		0.4		18.62
20.00 to 24.99		0.8		1.1		22.53		0.8		22.53
25.00 to 29.99		0.7		1.2		26.23		0.7		26.23
30.00 to 43.99		0.7		1.7		39.87		0.6		39.41
44.00 to 53.00		18.7		3.1		47.96		10.9		47.87

		21.3		2.4		45.42		13.4		43.90

The Company has recorded stock-based compensation expense in the Consolidated Statement of Earnings for stock options granted to employees and directors in 2003 using the fair-value method. Stock options granted in 2004 have an associated Tandem Share Appreciation Right attached. Compensation expense has not been recorded in the Consolidated Statement of Earnings related to stock options granted prior to 2003. If the Company had applied the fair-value method to options granted prior to 2003, pro forma Net Earnings and Net Earnings per Common Share for the three months ended September 30, 2004 would have been $384 million; $0.83 per common share — basic; $0.82 per common share - diluted (2003 — $281 million; $0.59 per common share — basic; $0.59 per common share — diluted). Pro forma Net Earnings and Net Earnings per Common Share for the nine months ended September 30, 2004 would have been $906 million; $1.97 per common share — basic; $1.94 per common share — diluted (2003 - $1,908 million; $3.99 per common share — basic; $3.94 per common share - diluted).


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

11. SHARE CAPITAL (continued)

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants as follows:


	September 30,
	2003
Weighted Average Fair Value of Options Granted (C$)	$	12.21
Risk Free Interest Rate		3.89	%
Expected Lives (years)		3.00
Expected Volatility		0.33
Annual Dividend per Share (C$)	$	0.40

12. COMPENSATION PLANS

The tables below outline certain information related to the Company’s compensation plans at September 30, 2004. Additional information is contained in Note 16 of the Company’s annual audited Consolidated Financial Statements for the year ended December 31, 2003.

A) Pensions

The following table summarizes the net benefit plan expense:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Current Service Cost	$	1		$	2		$	4		$	5
Interest Cost		3			3			9			9
Expected Return on Plan Assets		(2	)		(2	)		(8	)		(7	)
Amortization of Net Actuarial Loss		1			1			3			3
Amortization of Transitional Obligation		—			(1	)		(1	)		(2	)
Amortization of Past Service Cost		—			—			1			1
Expense for Defined Contribution Plan		3			3			10			9

Net Benefit Plan Expense	$	6		$	6		$	18		$	18

At September 30, 2004, $17 million has been contributed to the pension plans and the Company expects to make no additional contributions during the remainder of 2004.

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

The following table summarizes the information about SAR’s at September 30, 2004:


				Weighted Average
	Outstanding SAR’s			Exercise Price ($)
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year		1,175,070			35.87
Exercised		(497,785	)		35.15
Forfeited		(11,040	)		29.25

Outstanding, End of Period		666,245			36.52

Exercisable, End of Period		666,245			36.52

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year		753,417			28.98
Exercised		(279,258	)		29.27
Forfeited		(1,472	)		24.08

Outstanding, End of Period		472,687			28.82

Exercisable, End of Period		472,687			28.82


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

12. COMPENSATION PLANS (continued)

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

The following table summarizes the information about Tandem SAR’s at September 30, 2004:


	Outstanding Tandem			Weighted Average
	SAR’s			Exercise Price (C$)
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year		—			—
Granted		976,650			54.58
Forfeited		(77,500	)		54.24

Outstanding, End of Period		899,150			54.61

Exercisable, End of Period		—			—

C) Deferred Share Units (“DSU’s”)

The following table summarizes the information about DSU’s at September 30, 2004:


			Weighted Average
	Outstanding DSU’s		Exercise Price (C$)
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year		319,250		48.68
Granted, Directors		58,145		53.69
Granted, Senior Executives		1,686		57.54

Outstanding, End of Period		379,081		49.49

Exercisable, End of Period		297,874		51.82

D) Performance Share Units (“PSU’s”)

The following table summarizes the information about PSU’s at September 30, 2004:


				Weighted Average
	Outstanding PSU’s			Exercise Price ($)
Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year		126,283			46.52
Granted		1,687,571			53.97
Forfeited		(70,540	)		53.17

Outstanding, End of Period		1,743,314			53.46

Exercisable, End of Period		—			—

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year		—			—
Granted		249,830			41.12
Forfeited		(19,547	)		41.12

Outstanding, End of Period		230,283			41.12

Exercisable, End of Period		—			—


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ 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

Nine Months Ended

March 31,

June 30,

September 30,

(millions)

2004

2003

2004

2003

Weighted Average Common Shares Outstanding — Basic

460.9

460.3

461.7

473.4

461.0

478.0

Effect of Dilutive Securities

6.2

5.2

4.5

4.5

6.1

5.7

Weighted Average Common Shares Outstanding — Diluted

467.1

465.5

466.2

477.9

467.1

483.7

14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

As discussed in Note 2, on January 1, 2004, the fair value of all outstanding financial instruments that were not considered accounting hedges was recorded on the Consolidated Balance Sheet with an offsetting net deferred loss amount. The deferred loss is recognized into net earnings over the life of the related contracts. Changes in fair value after that time are recorded on the Consolidated Balance Sheet with the associated unrealized gain or loss recorded in net earnings. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third party market indications and forecasts.

The following table presents a reconciliation of the change in the unrealized amounts from January 1, 2004 to September 30, 2004:


				Net Deferred
				Amounts Recognized						Total Unrealized
		Acquired		on Transition			Fair Market Value			Gain/(Loss)
Fair Value of Contracts, January 1, 2004	(Note 2)	$	—	$	235		$	(235	)	$	—
Fair Value of Contracts Acquired with Tom Brown, Inc., Net of Amortization			5		—			(5	)		—
Change in Fair Value of Contracts Still Outstanding at September 30, 2004			—		—			(328	)		(328	)
Fair Value of Contracts Realized During the Period			—		(242	)		242			—
Fair Value of Contracts Entered into During the Period			—		—			(700	)		(700	)

Fair Value of Contracts Outstanding		$	5	$	(7	)	$	(1,026	)	$	(1,028	)

Premiums Paid on Collars and Options								24

Fair Value of Contracts Outstanding and Premiums Paid, End of Period							$	(1,002	)

The total realized loss recognized in net earnings for the quarter and year-to-date ended September 30, 2004 was $256 million ($173 million, net of tax) and $664 million ($449 million, net of tax), respectively.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

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

14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

At September 30, 2004, the net deferred amounts recognized on transition and the risk management amounts are recorded on the Consolidated Balance Sheet as follows:


	As at
	September 30, 2004
Deferred Amounts Recognized on Transition
Accounts receivable and accrued revenues	$	72
Investments and other assets		3
Accounts payable and accrued liabilities		30
Other liabilities		52

Total Net Deferred Loss	$	(7	)

Risk Management
Current asset	$	84
Long-term asset		46
Current liability		800
Long-term liability		332

Total Net Risk Management Liability	$	(1,002	)

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


	As at
	September 30, 2004
Commodity Price Risk
Natural gas	$	(500	)
Crude oil		(537	)
Power		6
Foreign Currency Risk		—
Interest Rate Risk		29

	$	(1,002	)

Information with respect to power, foreign currency risk and interest rate risk contracts in place at December 31, 2003 is disclosed in Note 17 to the Company’s annual audited Consolidated Financial Statements. No significant new contracts have been entered into as at September 30, 2004.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Natural Gas

At September 30, 2004, the Company’s gas risk management activities for financial contracts had an unrealized loss of $(495) million and a fair market value position of $(500) million. The contracts were as follows:


	Notional Volumes
	(MMcf/d)		Term		Average Price				Fair Market Value
Sales Contracts
Fixed Price Contracts
Fixed AECO price		454		2004		6.19		C$/Mcf	$	(34	)
NYMEX Fixed price		702		2004		5.15		US$/Mcf		(96	)
Colorado Interstate Gas (CIG)		52		2004		5.55		US$/Mcf		(1	)
Other ⁽¹⁾		162		2004		5.57		US$/Mcf		(10	)
NYMEX Fixed Price		180		2005		5.66		US$/Mcf		(79	)
Colorado Interstate Gas (CIG)		113		2005		4.87		US$/Mcf		(51	)
Other ⁽¹⁾		110		2005		5.21		US$/Mcf		(50	)
NYMEX Fixed Price		525		2006		5.66		US$/Mcf		(99	)
Colorado Interstate Gas (CIG)		100		2006		4.44		US$/Mcf		(35	)
Other ⁽¹⁾		171		2006		4.85		US$/Mcf		(60	)
Collars and Other Options
AECO Collars		73		2004		5.36 - 7.54		C$/Mcf		(3	)
NYMEX Collars		24		2004		4.45 - 5.95		US$/Mcf		(1	)
Purchased NYMEX Put Options		33		2004		5.00		US$/Mcf		—
Other ⁽²⁾		57		2004		4.31- 6.53		US$/Mcf		(1	)
Purchased NYMEX Put Options		474		2005		5.00		US$/Mcf		(17	)
Other ⁽²⁾		5		2005		4.56 - 7.23		US$/Mcf		(2	)
NYMEX 3-Way Call Spread		180		2005		5.00/6.69/7.69		US$/Mcf		(28	)
Basis Contracts
Fixed NYMEX to AECO Basis		325		2004		(0.54	)	US$/Mcf		9
Fixed NYMEX to Rockies Basis		303		2004		(0.50	)	US$/Mcf		12
Other ⁽³⁾		240		2004		(0.39	)	US$/Mcf		3
Fixed NYMEX to AECO Basis		877		2005		(0.66	)	US$/Mcf		38
Fixed NYMEX to Rockies Basis		268		2005		(0.49	)	US$/Mcf		21
Other ⁽³⁾		442		2005		(0.47	)	US$/Mcf		2
Fixed NYMEX to AECO Basis		464		2006-2008		(0.65	)	US$/Mcf		22
Fixed NYMEX to Rockies Basis		249		2006-2008		(0.57	)	US$/Mcf		6
Fixed NYMEX to CIG Basis		150		2006-2008		(0.76	)	US$/Mcf		(10	)
Fixed Rockies to CIG Basis		31		2006-2008		(0.10	)	US$/Mcf		—
Other ⁽³⁾		132		2006		(0.45	)	US$/Mcf		(1	)
Purchase Contracts
Fixed Price Contracts
Waha Purchase		30		2004		6.18		US$/Mcf		(1	)
Waha Purchase		27		2005		5.90		US$/Mcf		5
Waha Purchase		23		2006		5.32		US$/Mcf		4
Premiums Paid on 3-Way Call Spread										3

Total Natural Gas Financial Positions										(454	)
Gas Storage Financial Positions										(49	)
Gas Marketing Financial Positions ⁽⁴⁾										3

Total Fair Value Positions										(500	)
Contracts Acquired										5

Total Unrealized Loss on Financial Contracts									$	(495	)


⁽¹⁾	Other Fixed Price Contracts relate to various price points at Chicago, San Juan, Waha, Houston Ship Channel (HSC), Mid-Continent, Rockies and Texas Oklahoma.


⁽²⁾	Other Collars and Other Options relate to collars at Permian, San Juan, Waha, Colorado Interstate Gas (CIG), HSC, Mid-Continent, Rockies and Texas Oklahoma.


⁽³⁾	Other Basis Contracts relate to Chicago, San Juan, CIG, HSC, Mid-Continent, Waha and Ventura.


⁽⁴⁾	The gas marketing activities are part of the daily ongoing operations of the Company’s proprietary production management.


Interim Report		PREPARED IN US$

For the period ended September 30, 2004

EnCana Corporation

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

14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Crude Oil

At September 30, 2004, the Company’s oil risk management activities for all financial contracts had an unrealized loss of $(558) million and a fair market value position of $(537) million. The contracts were as follows:


	Notional Volumes					Average Price
	(bbl/d)			Term		(US$/bbl)		Fair Market Value
Fixed WTI NYMEX Price		62,500			2004		23.13	$	(148	)
Collars on WTI NYMEX		62,500			2004		20.00-25.69		(133	)
Unwind WTI NYMEX Fixed Price		(9,000	)		2004		39.22		8
Purchased WTI NYMEX Call Options		(111,000	)		2004		46.64		29
Fixed WTI NYMEX Price		45,000			2005		28.41		(260	)
Costless 3-Way Put Spread		10,000			2005		20.00/25.00/28.78		(56	)
Unwind WTI NYMEX Fixed Price		(4,500	)		2005		35.90		14
Purchased WTI NYMEX Call Options		(38,000	)		2005		49.76		18
Fixed WTI NYMEX Price		15,000			2006		34.56		(27	)
Purchased WTI NYMEX Put Options		17,000			2006		26.59		(3	)

									(558	)
Crude Oil Marketing Financial Positions ⁽¹⁾									—

Total Unrealized Loss on Financial Contracts									(558	)
Premiums Paid on Call Options									21

Total Fair Value Positions								$	(537	)


⁽¹⁾	The crude oil marketing activities are part of the daily ongoing operations of the Company’s proprietary production management.

15. COMMITMENTS AND CONTINGENCIES

Ecuador

In Ecuador, a subsidiary of the Company has a 40 percent economic interest in relation to Block 15 pursuant to a contract with a subsidiary of Occidental Petroleum Corporation. During the third quarter, Occidental Petroleum Corporation filed a Form 8-K indicating that its subsidiary had received formal notification from Petroecuador, the state oil company of Ecuador, initiating proceedings to determine if the subsidiary had violated the Hydrocarbons Law and its Participation Contract for Block 15 with Petroecuador and whether such violations constitute grounds for terminating the Participation Contract.

In its Form 8-K, Occidental Petroleum Corporation indicated that it believes it has complied with all material obligations under the Participation Contract and that any termination of the Participation Contract by Ecuador based upon these stated allegations would be unfounded and would constitute an unlawful expropriation under international treaties.

16. RECLASSIFICATION

Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2004.

EnCana Corporation
Management’s Discussion and Analysis
October 26, 2004

This Management’s Discussion and Analysis (“MD&A”) for EnCana Corporation (“EnCana” or the “Company”) should be read in conjunction with the unaudited interim Consolidated Financial Statements (“Interim Consolidated Financial Statements”) for the three and nine months ended September 30, 2004, as well as the audited Consolidated Financial Statements and MD&A for the year ended December 31, 2003. Readers are referred to the legal advisory detailing “Note Regarding Forward-Looking Statements” contained in the back of this MD&A. Certain definitions used in this MD&A are defined in the sections found at the back of this MD&A entitled “Note Regarding Oil and Gas Information” and “Note Regarding Currency, Protocols and Non-GAAP Measures”. The Interim Consolidated Financial Statements and comparative information have been prepared in accordance with Canadian GAAP in the currency of the United States (except where indicated as being in another currency). The production and sales volumes in this MD&A and the supplementary information in the Interim Consolidated Financial Statements, have been presented on an after royalties basis consistent with U.S. protocol reporting. This MD&A is dated October 26, 2004.

OVERVIEW

Summary of Key Events and Key Financial Results in the Third Quarter

Third quarter 2004 compared to third quarter 2003:

•

Upstream sales volumes increased by 22 percent to 780,741 BOE per day.

•

North American natural gas prices (excluding financial hedges), averaged $5.18 per Mcf in 2004 compared to $4.66 per Mcf in 2003, an increase of 11 per cent.

•

Liquids prices (excluding financial hedges), averaged $32.83 per barrel in 2004 compared to $21.22 in 2003, an increase of 55 percent.

•

Operating expenses and corporate administration costs decreased on a BOE basis by $0.15 and $0.10 respectively.

•

As part of the continuing alignment of the North American assets with EnCana’s unconventional resource play strategy the Company completed $940 million in mature conventional property dispositions.

•

Reduction in long-term debt (including current portion) during the third quarter in 2004 of $729 million.

•

Realized financial commodity and currency hedge losses of approximately $265 million ($180 million after-tax) in 2004 compared to a $58 million ($40 million after-tax) loss for 2003.

•

Mark-to-market accounting for derivative instruments resulted in a $497 million ($321 million after-tax) charge to earnings for unrealized losses in 2004 with no corresponding amount in 2003 since mark-to-market accounting was adopted as of January 1, 2004.

•

A $193 million ($155 million after-tax) unrealized gain on Canadian issued U.S. dollar debt in 2004 compared to an unrealized gain of $15 million ($12 million after-tax) in 2003.

•

A $95 million ($79 million after-tax) realized foreign exchange gain in 2004 compared to a realized gain of $5 million ($3 million after-tax) in 2003.

•

Current income tax provision increased to $124 million in 2004 compared to a tax provision of $51 million in 2003, for a total increase in cash taxes of $73 million.

- 1 -

CONSOLIDATED FINANCIAL RESULTS


	Three Months Ended							Nine Months Ended							Year
	September 30							September 30							Ended
Consolidated Financial Summary	2004 vs							2004 vs
($ millions, except per share amounts)	2004		2003			2003		2004		2003			2003		2003
Revenues, Net of Royalties	$	2,458		7	%	$	2,291	$	8,026		9	%	$	7,366	$	10,216
Net Earnings from Continuing Operations		393		37	%		286		933		-46	%		1,741		2,167
- per share - basic		0.85		42	%		0.60		2.02		-45	%		3.64		4.57
- per share - diluted		0.84		40	%		0.60		2.00		-44	%		3.60		4.52
Net Earnings		393		36	%		290		933		-52	%		1,934		2,360
- per share - basic		0.85		39	%		0.61		2.02		-50	%		4.05		4.98
- per share - diluted		0.84		38	%		0.61		2.00		-50	%		4.00		4.92
Operating Earnings ⁽¹⁾		559		104	%		274		1,403		32	%		1,059		1,375
- per share - diluted		1.20		111	%		0.57		3.00		37	%		2.19		2.87
Cash Flow from Continuing Operations ⁽²⁾		1,363		40	%		973		3,489		9	%		3,203		4,420
- per share - basic		2.95		43	%		2.06		7.57		13	%		6.70		9.32
- per share - diluted		2.92		43	%		2.04		7.47		13	%		6.62		9.21
Cash Flow ⁽²⁾		1,363		40	%		977		3,489		9	%		3,205		4,459
- per share - basic		2.95		43	%		2.06		7.57		13	%		6.71		9.41
- per share - diluted		2.92		43	%		2.04		7.47		13	%		6.63		9.30

⁽¹⁾		Operating Earnings is a non- GAAP measure and is described and discussed under “Operating Earnings” in this MD&A.

⁽²⁾		Cash Flow from Continuing Operations and Cash Flow are non- GAAP measures and are discussed under “Cash Flow” in this MD&A.

Quarterly Summary


	2004						2003								2002
($ millions, except per share amounts)	Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4
Revenues, Net of Royalties	$	2,458	$	2,718	$	2,850	$	2,850	$	2,291	$	2,332	$	2,743	$	2,116
Net Earnings from Continuing Operations		393		250		290		426		286		805		650		248
- per share - basic		0.85		0.54		0.63		0.92		0.60		1.67		1.35		0.52
- per share - diluted		0.84		0.54		0.62		0.91		0.60		1.66		1.34		0.51
Net Earnings		393		250		290		426		290		807		837		282
- per share - basic		0.85		0.54		0.63		0.92		0.61		1.68		1.74		0.59
- per share - diluted		0.84		0.54		0.62		0.91		0.61		1.67		1.73		0.58
Operating Earnings ⁽¹⁾		559		379		465		316		274		275		510		239
- per share - diluted		1.20		0.81		1.00		0.68		0.57		0.56		1.05		0.49
Cash Flow from Continuing Operations ⁽²⁾		1,363		1,131		995		1,217		973		1,039		1,191		874
- per share - basic		2.95		2.46		2.16		2.63		2.06		2.16		2.48		1.83
- per share - diluted		2.92		2.43		2.13		2.61		2.04		2.14		2.46		1.81
Cash Flow ⁽²⁾		1,363		1,131		995		1,254		977		1,007		1,221		935
- per share - basic		2.95		2.46		2.16		2.71		2.06		2.10		2.54		1.96
- per share - diluted		2.92		2.43		2.13		2.69		2.04		2.08		2.52		1.94

(1)		Operating Earnings is a non- GAAP measure and is described and discussed under “Operating Earnings” in this MD&A.

(2)		Cash Flow from Continuing Operations and Cash Flow are non- GAAP measures and are discussed under “Cash Flow” in this MD&A.

- 2 -

Cash Flow

EnCana’s cash flow from continuing operations increased $390 million, or $0.88 per share diluted, in the third quarter of 2004 compared to the same period in 2003 and increased $286 million, or $0.85 per share diluted, during the first nine months of 2004 compared to the first nine months in 2003. Significant items are as follows:

Third quarter 2004 compared to third quarter 2003:

•

Natural gas sales volumes increased 24 percent to 3,128 MMcf per day.

•

Crude oil and NGLs sales volumes increased 19 percent to 259,408 barrels per day.

•

North American natural gas prices (excluding financial hedges), were $5.18 per Mcf in 2004 compared to $4.66 per Mcf in 2003, an increase of 11 percent.

•

Liquids prices (excluding financial hedges), are $32.83 per barrel in 2004 compared to $21.22 in 2003, an increase of 55 percent.

•

Operating expenses are $3.38 per BOE in 2004 compared to $3.53 per BOE in 2003, a decrease of $0.15 per BOE.

•

Corporate administration costs are $0.60 per BOE in 2004 compared to $0.70 per BOE in 2003, a reduction of $0.10 per BOE.

•

Realized financial commodity and currency hedge losses are approximately $265 million ($180 million after-tax) in 2004 (comprised of $0.15 per Mcf on natural gas and $9.28 per barrel on liquids) compared to $58 million ($40 million after-tax) for 2003 (comprised of $0.06 per Mcf on natural gas and $2.18 per barrel on liquids).

•

A $95 million ($79 million after-tax) realized foreign exchange gain in 2004 compared to a realized gain of $5 million ($3 million after-tax) in 2003 primarily as a result of the rise in the U.S./Canadian dollar exchange rate and its impact on Canadian issued U.S. denominated debt.

•

Current tax provision increased by $73 million to $124 million in 2004 from $51 million in 2003 partially offsetting increased cash flow from higher volumes and prices.

Nine months ended September 2004 compared to nine months ended September 2003:

•

Crude oil and NGLs sales volumes increased 27 percent to 264,672 barrels per day.

•

Natural gas sales volumes increased 17 percent to 2,960 MMcf per day.

•

North American natural gas prices (excluding financial hedges), are $5.26 per Mcf in 2004 compared to $5.01 per Mcf in 2003, an increase of 5 percent.

•

Liquids prices (excluding financial hedges), are $28.67 per barrel in 2004 compared to $23.57 in 2003, an increase of 22 percent.

•

Realized financial commodity and currency hedge losses are approximately $648 million ($439 million after-tax) in 2004 (comprised of $0.16 per Mcf on natural gas and $7.11 per barrel on liquids) compared to $283 million ($194 million after-tax) for 2003 (comprised of $0.19 per Mcf on natural gas and $2.71 per barrel on liquids).

•

An $87 million ($71 million after-tax) realized foreign exchange gain in 2004 compared to a realized gain of $32 million ($18 million after-tax) in 2003 primarily as a result of the rise in the U.S./Canadian dollar exchange rate and its impact on Canadian issued U.S. denominated debt.

•

Current tax provision increased by $542 million to $559 million in 2004 from $17 million in 2003 partially offsetting increased cash flow from higher volumes and prices.

Cash flow is a non-GAAP measure but is commonly used in the oil and gas industry to assist management and investors to measure the Company’s ability to finance its capital programs and meet its credit obligations. The calculation of cash flow is disclosed on the Consolidated Statement of Cash Flows in the Interim Consolidated Financial Statements.

Net Earnings

EnCana’s net earnings from continuing operations increased $107 million, or $0.24 per share diluted in the third quarter of 2004 compared to the same period in 2003 and decreased $808 million, or $1.60 per share diluted during the first nine months of 2004 compared to the first nine months in 2003. In addition to the items affecting cash flow as detailed previously, significant items are:

- 3 -

Third quarter 2004 compared to third quarter 2003:

•

Mark-to-market accounting for derivative instruments resulted in a $497 million ($321 million after-tax, $0.69 per share diluted) charge to earnings for unrealized losses in 2004 with no corresponding amount in 2003.

•

A $193 million ($155 million after-tax, $0.33 per share diluted) unrealized gain on Canadian issued U.S. dollar debt in 2004 compared to an unrealized gain of $15 million ($12 million after-tax, $0.03 per share diluted) in 2003 as a result of a larger increase in the period end U.S./Canadian dollar exchange rate between June 30, 2004 and September 30, 2004 compared to the same period in 2003.

Nine months ended September 2004 compared to nine months ended September 2003:

•

Unrealized mark-to-market losses of $1,028 million ($677 million after-tax, $1.44 per share diluted) are included in 2004 with no corresponding amount in 2003.

•

Included in 2004 is a gain due to a change in tax rates of $109 million or $0.23 per share diluted, compared to a gain of $362 million, or $0.75 per share diluted, in 2003.

•

A $122 million ($98 million after-tax, $0.21 per share diluted) unrealized gain on Canadian issued U.S. dollar debt in 2004 compared to an unrealized gain of $404 million ($320 million after-tax, $0.66 per share diluted) in 2003 as a result of a small increase in the period end U.S./Canadian dollar exchange rate between December 31, 2003 and September 30, 2004 compared to significant appreciation in the period end U.S./Canadian dollar exchange rate between December 31, 2002 and September 30, 2003.

Net earnings in the third quarter of 2003 include $4 million, or $0.01 per share diluted, from discontinued operations and on a year-to-date basis net earnings in 2003 include $193 million, or $0.40 per share diluted, from discontinued operations.

Impacts on results due to the change in the U.S./Canadian dollar exchange rate need to be considered when analyzing specific components contained in the Interim Consolidated Financial Statements. For every 100 dollars denominated in Canadian currency spent on capital projects, operating expenses and administrative expenses, the Company incurred additional costs, as reported in U.S. dollars, of approximately $4.00 ($5.20 year-to-date) based on the increase in the average U.S./Canadian dollar exchange rate from the third quarter of 2003 of $0.725 ($0.701 year-to-date) to the third quarter of 2004 of $0.765 ($0.753 year-to-date). Revenues were relatively unaffected by the increased exchange rate since commodity prices received are largely based in U.S. dollars or in Canadian dollar prices which are closely tied to the value of the U.S. dollar.

Operating Earnings

Operating earnings is a non-GAAP measure that shows net earnings from continuing operations excluding the after-tax effects of unrealized mark-to-market accounting for derivative instruments, the gain/loss on translation of U.S. dollar denominated debt issued in Canada and the effect of the reduction in income tax rates. The following table has been prepared in order to provide shareholders and potential investors with information clearly presenting the effect on the Company’s results of mark-to-market accounting for derivative financial instruments, the translation of the outstanding U.S. dollar debt issued in Canada and the effect of the reduction in the Canadian and Alberta tax rates. Management believes these items reduce the comparability of the Company’s underlying financial performance between periods. The majority of the unrealized gains/losses on U.S. dollar debt issued in Canada relate to debt with maturity dates in excess of five years.

- 4 -

Quarterly Summary of Operating Earnings


	2004								2003												2002
($ millions)	Q3			Q2		Q1			Q4			Q3			Q2			Q1			Q4
Net Earnings from Continuing Operations, as reported	$	393		$	250	$	290		$	426		$	286		$	805		$	650		$	248
Add: Unrealized mark-to-market accounting loss (after-tax) ⁽²⁾		321			104		252			—			—			—			—			—
Add: Unrealized foreign exchange (gain) loss on translation of Canadian issued U.S. dollar debt (after-tax)		(155	)		25		32			(113	)		(12	)		(168	)		(140	)		(6	)
Add: Future tax (recovery) expense due to tax rate reductions		—			—		(109	)		3			—			(362	)		—			(3	)

Operating Earnings ⁽¹⁾⁽³⁾	$	559		$	379	$	465		$	316		$	274		$	275		$	510		$	239

*($ per Common Share - Diluted)*
Net Earnings from Continuing Operations, as reported	$	0.84		$	0.54	$	0.62		$	0.91		$	0.60		$	1.66		$	1.34		$	0.51
Add: Unrealized mark-to-market accounting loss (after-tax) ⁽²⁾		0.69			0.22		0.54			—			—			—			—			—
Add: Unrealized foreign exchange (gain) loss on translation of Canadian issued U.S. dollar debt (after-tax)		(0.33	)		0.05		0.07			(0.24	)		(0.03	)		(0.35	)		(0.29	)		(0.01	)
Add: Future tax (recovery) expense due to tax rate reductions		—			—		(0.23	)		0.01			—			(0.75	)		—			(0.01	)

Operating Earnings ⁽¹⁾⁽³⁾	$	1.20		$	0.81	$	1.00		$	0.68		$	0.57		$	0.56		$	1.05		$	0.49

(1)		Operating Earnings is a non-GAAP measure that shows net earnings from continuing operations excluding the after-tax effects of unrealized mark-to-market accounting for derivative instruments, the (gain)/loss on translation of U. S. dollar denominated debt issued in Canada and the effect of the reduction in income tax rates.

(2)		The Company adopted mark-to-market accounting on derivative financial instruments prospectively January 1, 2004. See Note 2 of the Interim Consolidated Financial Statements.

(3)		Unrealized (gains)/losses have no impact on cash flow.

Year-to-Date Summary of Operating Earnings


	Three Months Ended September 30									Nine Months Ended September 30
	2004 vs									2004 vs
($ millions)	2004			2003			2003			2004			2003			2003
Net Earnings from Continuing Operations, as reported	$	393			37	%	$	286		$	933			-46	%	$	1,741
Add: Unrealized mark-to-market accounting loss (after-tax) ⁽²⁾		321			—			—			677			—			—
Add: Unrealized foreign exchange (gain) loss on translation of Canadian issued U.S. dollar debt (after-tax)		(155	)		1192	%		(12	)		(98	)		-69	%		(320	)
Add: Future tax (recovery) expense due to tax rate reductions		—			—			—			(109	)		-70	%		(362	)

Operating Earnings ⁽¹⁾⁽³⁾	$	559			104	%	$	274		$	1,403			32	%	$	1,059

*($ per Common Share - Diluted)*
Net Earnings from Continuing Operations, as reported	$	0.84			40	%	$	0.60		$	2.00			-44	%	$	3.60
Add: Unrealized mark-to-market accounting loss (after-tax) ⁽²⁾		0.69			—			—			1.44			—			—
Add: Unrealized foreign exchange (gain) loss on translation of Canadian issued U.S. dollar debt (after-tax)		(0.33	)		1000	%		(0.03	)		(0.21	)		-68	%		(0.66	)
Add: Future tax (recovery) expense due to tax rate reductions		—			—			—			(0.23	)		-69	%		(0.75	)

Operating Earnings ⁽¹⁾⁽³⁾	$	1.20			111	%	$	0.57		$	3.00			37	%	$	2.19

(1)		Operating Earnings is a non-GAAP measure that shows net earnings from continuing operations excluding the after-tax effects of unrealized mark-to-market accounting for derivative instruments, the (gain)/loss on translation of U.S. dollar denominated debt issued in Cana da and the effect of the reduction in income tax rates.

(2)		The Company adopted mark-to-market accounting on derivative financial instruments prospectively January 1, 2004. See Note 2 of the Interim Consolidated Financial Statements.

(3)		Unrealized (gains)/losses have no impact on cash flow.

		- 5 -

Cash Flow from Continuing Operations and Current Income Tax

Changes to cash flow from continuing operations, when comparing 2004 to prior periods are significantly impacted by changes in the provision for current income tax. The following table has been prepared to disclose the quarterly cash flow from continuing operations and the current income tax provision.


($ millions)	2004						2003										2002
	Q3		Q2		Q1		Q4			Q3		Q2			Q1		Q4
Cash Flow from Continuing Operations	$	1,363	$	1,131	$	995	$	1,217		$	973	$	1,039		$	1,191	$	874
Current Income Tax⁽¹⁾	$	124	$	203	$	232	$	(73	)	$	51	$	(54	)	$	20	$	(107	)

(1)

Amount deducted (added) in determining Cash Flow from Continuing Operations.

Current income tax is discussed in the “Corporate” area under “Results of Operations” in this MD&A.

RESULTS OF OPERATIONS

Upstream Operations

Financial Results ($ millions)


Three Months Ended September 30	2004								2003
	Produced		Crude Oil						Produced		Crude Oil
	Gas		and NGLs		Other		Total		Gas		and NGLs			Other		Total
Revenues, Net of Royalties	$	1,442	$	562	$	66	$	2,070	$	1,067	$	384		$	58	$	1,509
Expenses
Production and mineral taxes		69		28		—		97		40		(7	)		—		33
Transportation and selling		102		38		—		140		94		20			—		114
Operating		131		113		60		304		107		100			51		258

Operating Cash Flow	$	1,140	$	383	$	6	$	1,529	$	826	$	271		$	7	$	1,104

Depreciation, depletion and amortization								672									502

Upstream Income							$	857								$	602


Nine Months Ended September 30	2004								2003
	Produced		Crude Oil						Produced		Crude Oil
	Gas		and NGLs		Other		Total		Gas		and NGLs		Other		Total
Revenues, Net of Royalties	$	4,121	$	1,562	$	170	$	5,853	$	3,318	$	1,186	$	147	$	4,651
Expenses
Production and mineral taxes		188		70		—		258		110		21		—		131
Transportation and selling		334		114		—		448		255		76		—		331
Operating		377		329		155		861		301		284		134		719

Operating Cash Flow	$	3,222	$	1,049	$	15	$	4,286	$	2,652	$	805	$	13	$	3,470

Depreciation, depletion and amortization								1,947								1,444

Upstream Income							$	2,339							$	2,026

Consolidated Upstream Results

Overall results reflect a 22 percent increase in sales volumes of 141,418 BOE per day during the third quarter 2004 and a 21 percent increase in sales volumes of 129,069 BOE per day for the nine months ended September 30, 2004 compared with the same periods in 2003.

Revenues, net of royalties reflects the increase in natural gas and crude oil benchmark prices (see the “Business Environment” section of this MD&A) for both the third quarter and year-to-date results offset by the realized hedging losses. The effect of realized commodity and currency hedging losses was $265 million, or $3.69 per BOE, in the third

- 6 -

quarter 2004 compared to $58 million, or $0.99 per BOE, in the three month period ended September 30, 2003. For the nine months ended September 30, 2004, realized commodity and currency hedge losses were $648 million, or $3.12 per BOE, compared to $283 million or $1.65 per BOE, for the same period in 2003.

Operating expenses in the third quarter of 2004 averaged $3.38 per BOE compared to $3.53 per BOE in 2003. For the nine months ended September 30, 2004, operating expenses were relatively unchanged at $3.39 per BOE compared to $3.41 per BOE for the same period in 2003.

Depreciation, depletion and amortization (“DD&A”) expense increased by $170 million in the third quarter of 2004 and $503 million year-to-date September 30, 2004, compared to the same periods in 2003 primarily as a result of increased sales volumes and the impact of the higher value of the Canadian dollar compared to the U.S. dollar applied to Canadian dollar denominated DD&A expense. On a BOE basis, excluding Other activities, DD&A rates were $9.27 per BOE for the third quarter of 2004 compared to $8.49 per BOE in the same period of 2003. DD&A rates were $9.23 per BOE for the first nine months of 2004 compared to $8.38 per BOE in the same period of 2003. Increased DD&A rates in the third quarter and on a year-to-date basis in 2004 were primarily the result of the increase in the average U.S./Canadian dollar exchange rate and the acquisition of Tom Brown Inc. (“TBI’). DD&A rates for the nine months ended September 30, 2004 exclude the impairment of an Upstream international exploration prospect in Ghana which was recorded and disclosed in the second quarter of 2004.

Revenue Variances for 2004 Compared to 2003 ($ millions) ⁽¹⁾


	Three Months Ended September 30									Nine Months Ended September 30
	2003							2004		2003							2004
	Revenues,		Revenue Variances					Revenues,		Revenues,		Revenue Variances					Revenues,
	Net of		in:					Net of		Net of		in:					Net of
	Royalties		Price ⁽²⁾		Volume			Royalties		Royalties		Price⁽²⁾			Volume		Royalties
Produced Gas
Canada	$	806	$	62	$	102		$	970	$	2,534	$	132		$	221	$	2,887
United States		259		32		171			462		776		45			377		1,198
U.K. North Sea		2		—		8			10		8		4			24		36

Total Produced Gas	$	1,067	$	94	$	281		$	1,442	$	3,318	$	181		$	622	$	4,121

Crude Oil and NGLs
Canada	$	266	$	64	$	(17	)	$	313	$	809	$	55		$	19	$	883
United States		22		10		18			50		69		19			27		115
Ecuador		81		4		74			159		243		(44	)		233		432
U.K. North Sea		15		1		24			40		65		(3	)		70		132

Total Crude Oil and NGLs	$	384	$	79	$	99		$	562	$	1,186	$	27		$	349	$	1,562

(1)		Includes continuing operations only.

(2)		Includes realized commodity hedging impacts.

The increase in sales volumes accounts for approximately 69 percent of the change in revenues, net of royalties in the third quarter of 2004 and approximately 82 percent for the first nine months of 2004. In the table above, impacts from price changes are reduced as a result of the period over period changes in realized commodity and currency hedge losses mentioned previously.

- 7 -


Quarterly Sales Volumes
(After Royalties)	2004								2003											2002
	Q3⁽⁴⁾			Q2			Q1		Q4		Q3			Q2			Q1			Q4
Produced Gas (MMcf per day)
Canada
Production		2,138			2,177			2,000		2,008		1,914			1,899			1,922			1,943
Inventory withdrawal		—			—			—		—		—			—			120			117

Canada Sales ⁽⁵⁾		2,138			2,177			2,000		2,008		1,914			1,899			2,042			2,060
United States ⁽⁵⁾		958			824			684		654		604			558			534			516
United Kingdom		32			36			28		20		7			12			13			8

		3,128			3,037			2,712		2,682		2,525			2,469			2,589			2,584

Oil and NGLs (bbls per day) ⁽¹⁾
Canada Sales ⁽⁵⁾		154,726			157,935			156,640		164,859		163,179			149,292			148,147			148,196
United States ⁽⁵⁾		14,947			12,752			9,237		9,612		9,691			10,376			8,148			10,162
Ecuador
Production		76,567			78,376			76,320		72,731		54,582			36,754			39,893			34,856
Transferred to OCP Pipeline ⁽²⁾		—			—			—		—		(4,919	)		(2,039	)		(5,941	)		—
Over / (under) lifting		(1,721	)		(73	)		4,662		4,621		(9,856	)		2,506			(2,679	)		1,044

Ecuador Sales		74,846			78,303			80,982		77,352		39,807			37,221			31,273			35,900
United Kingdom		14,889			20,728			18,088		15,067		5,813			9,019			10,610			7,786

		259,408			269,718			264,947		266,890		218,490			205,908			198,178			202,044

Total (BOE per day) ⁽³⁾		780,741			775,885			716,947		713,890		639,323			617,408			629,678			632,711

(1)		NGLs include Condensate.

(2)		Crude oil product ion in Ecuador transferred to the OCP Pipeline for use by OCP in asset commissioning.

(3)		Natural gas converted to BOE at 6 Mcf = 1 BOE.

(4)		Quarterly volumes reflect decreases as a result of the 2004 property dispositions of 81 MMcf/d in natural gas and 22 Mbbls/d of liquids or a total of approximately 36 MBOE/d.

(5)		Includes Tom Brown, Inc. sales volumes in 2004:


	Natural Gas (MMcf/d)				Oil and NGLs (bbls/d)
	Q3		Q2		Q3		Q2
Canada		18		9		923		511
United States		257		123		4,949		2,689

Total Volumes		275		132		5,872		3,200

- 8 -

Year-to-Date Sales Volumes Ended September 30


(After Royalties)	Three Months Ended September 30									Nine Months Ended September 30
	2004 vs									2004 vs
	2004⁽⁴⁾			2003			2003			2004⁽⁵⁾		2003			2003
Produced Gas (MMcf per day)
Canada
Production		2,138			12	%		1,914			2,105		10	%		1,913
Inventory withdrawal		—			—			—			—		—			38

Canada Sales ⁽⁶⁾		2,138			12	%		1,914			2,105		8	%		1,951
United States ⁽⁶⁾		958			59	%		604			823		45	%		566
United Kingdom		32			357	%		7			32		191	%		11

		3,128			24	%		2,525			2,960		17	%		2,528

Oil and NGLs (bbls per day) ⁽¹⁾
Canada Sales ⁽⁶⁾		154,726			-5	%		163,179			156,428		2	%		153,595
United States ⁽⁶⁾		14,947			54	%		9,691			12,322		31	%		9,413
Ecuador
Production		76,567			40	%		54,582			77,086		76	%		43,797
Transferred to OCP Pipeline ⁽²⁾		—			—			(4,919	)		—		—			(4,296	)
Over / (under) lifting		(1,721	)		—			(9,856	)		946		—			(3,369	)

Ecuador Sales		74,846			88	%		39,807			78,032		116	%		36,132
United Kingdom		14,889			156	%		5,813			17,890		111	%		8,463

		259,408			19	%		218,490			264,672		27	%		207,603

Total (BOE per day) ⁽³⁾		780,741			22	%		639,323			758,005		21	%		628,936

(1)		NGLs include Condensate.

(2)		Crude oil production in Ecuador transferred to the OCP Pipeline for use by OCP in asset commissioning.

(3)		Natural gas converted to BOE at 6 Mcf = 1 BOE.

(4)		Quarterly volumes reflect decreases as a result of the 2004 property dispositions of 81 MMcf/d in natural gas and 22 Mbbls/d of liquids or a total of approximately 36 MBOE/d.

(5)		Year-to-date volumes reflect decreases as a result of the 2004 property dispositions of 41 MMcf/d in natural gas and 16 Mbbls/d of liquids or a total of approximately 23 MBOE/d.

(6)		2004 Includes sales volumes from the acquisition of TBI. For the three months ended September 30 sales volumes from North America included 275 MMcf/d of natural gas and 5,872 bbls/d of liquids. For the nine months ended September 30 sales volumes from North America included 136 MMcf/ d of natural gas and 3,035 bbls/d of liquids.

On a year-to-date basis, 2004 volumes are higher by 21 percent, or 129,069 BOE per day, compared to 2003. Increases in Canadian natural gas sales volumes in the third quarter and on a year-to-date basis in 2004 were primarily the result of successful resource play drilling programs at Greater Sierra and Cutbank Ridge in northeast British Columbia as well as southern plains shallow gas in Alberta. Third quarter 2004 natural gas sales volumes in the United States increased as a result of the TBI acquisition in the second quarter of 2004 and successful drilling program at Mamm Creek. Higher natural gas sales volumes in the United States for the first nine months of 2004 were primarily the result of successful resource play drilling programs at Mamm Creek, Jonah and North Texas and the TBI acquisition.

Increases in liquids sales volumes in the third quarter and for the first nine months of 2004 are primarily the result of the commencement of sales on the OCP Pipeline in Ecuador in September 2003 and the increased interests in the Scott and Telford fields in the United Kingdom. Increases in North American liquids sales in the third quarter of 2004 resulting from development at Foster Creek and Pelican Lake were more than offset by the reduction in volumes resulting from the Petrovera disposition in the first quarter of 2004 and additional non-core dispositions that closed in the third quarter of 2004. For the first nine months of 2004, North American liquids sales volumes were higher when compared to the same

- 9 -

period in 2003 as a result of continued Foster Creek development, successful drilling programs at Suffield and positive response from the waterflood program at Pelican Lake offset partially by the Petrovera disposition and additional non-core dispositions in the third quarter of 2004.

Per Unit Results – Produced Gas ($ per thousand cubic feet)


Three Months Ended September 30	Canada							United States							United Kingdom
	2004 vs							2004 vs							2004 vs
	2004		2003			2003		2004		2003			2003		2004		2003			2003
Price ⁽¹⁾	$	5.10		11	%	$	4.61	$	5.36		11	%	$	4.82	$	3.84		47	%	$	2.62
Expenses
Production and mineral taxes		0.09		13	%		0.08		0.57		24	%		0.46		—		—			—
Transportation and selling		0.37		-8	%		0.40		0.26		-33	%		0.39		2.34		-11	%		2.63
Operating		0.50		—			0.50		0.36		9	%		0.33		—		—			—

Netback	$	4.14				$	3.63	$	4.17				$	3.64	$	1.50				$	(0.01	)

Gas Sales Volumes (MMcf per day)		2,138		12	%		1,914		958		59	%		604		32		357	%		7

(1)

Excludes realized commodity and currency hedge activities.


Nine Months Ended September 30	Canada							United States							United Kingdom
	2004 vs							2004 vs							2004 vs
	2004		2003			2003		2004		2003			2003		2004		2003			2003
Price ⁽¹⁾	$	5.17		3	%	$	5.03	$	5.49		11	%	$	4.95	$	4.07		47	%	$	2.76
Expenses
Production and mineral taxes		0.08		33	%		0.06		0.63		29	%		0.49		—		—			—
Transportation and selling ⁽²⁾		0.38		6	%		0.36		0.32		-11	%		0.36		2.28		6	%		2.16
Operating		0.52		6	%		0.49		0.36		29	%		0.28		—		—			—

Netback	$	4.19				$	4.12	$	4.18				$	3.82	$	1.79				$	0.60

Gas Sales Volumes (MMcf per day)		2,105		8	%		1,951		823		45	%		566		32		191	%		11

(1)		Excludes realized commodity and currency hedge activities.

(2)		U.S. per unit transportation and selling costs in 2004 exclude a one-time payment of $21 million made to terminate a long-term physical delivery contract.

Average natural gas prices, excluding the impact of financial hedges, in the third quarter of 2004 reflect the increase in the benchmark NYMEX and AECO gas prices, offset partially by the increased applicable differentials compared to the same period of 2003. Higher benchmark NYMEX prices of 16 percent in the quarter (3 percent year-to-date) compared to the same period in 2003 was partially offset by increased natural gas price differentials. Realized commodity and currency hedging losses on natural gas were approximately $44 million, or $0.15 per Mcf in the third quarter of 2004 compared to a loss of approximately $14 million, or $0.06 per Mcf in the third quarter 2003. On a year-to-date basis to September 30, realized commodity and currency hedging losses on natural gas were approximately $133 million, or $0.16 per Mcf in 2004 compared to a loss of approximately $129 million, or $0.19 per Mcf in 2003.

Per unit production and mineral taxes in the U.S. in the quarter and for the nine months ended September 30, 2004 compared to the same periods in 2003 increased due to a combination of higher prices and a higher effective tax rate in Colorado caused by the significant growth in Colorado production.

On a year-to-date basis the per unit transportation and selling costs for Canadian natural gas have increased as a result of higher average distances to sales markets from production facilities and the increased U.S./Canadian exchange rate. Natural gas per unit transportation and selling costs for the U.S. have decreased in the quarter and for the nine months ended September 30, 2004 compared to the same periods in 2003 as a result of the TBI acquisition where a majority of the production is sold at the wellhead and does not incur additional transportation charges. The U.K. increase in transportation and selling expense year-to-date 2004 compared to the same period in 2003 reflects a change in the cost sharing

- 10 -

arrangements for the Scottish Area Gas Evacuation (“SAGE”) pipeline as a result of the 2004 acquisition of additional interests in the Scott and Telford fields.

Canadian natural gas per unit operating expenses were unchanged in the third quarter of 2004 compared to the same period in 2003 but $0.03 higher on a year-to-date basis primarily due to the higher U.S./Canadian exchange rates. Increases in the U.S. per unit natural gas operating expenses for the third quarter and for the nine months ended September 30, 2004 compared to the same periods in 2003 were a result of higher operating costs from the TBI and North Texas property acquisitions and non-recurring charges related to the prior year.

Per Unit Results — Crude Oil and NGLs

Three Months Ended September 30

Crude Oil ($ per barrel)


	North America								Ecuador							United Kingdom
	2004 vs								2004 vs							2004 vs
	2004		2003			2003			2004		2003			2003		2004		2003			2003
Price ⁽¹⁾	$	31.49		55	%	$	20.26		$	33.47		51	%	$	22.13	$	40.88		46	%	$	27.92
Expenses
Production and mineral taxes		0.34		143	%		(0.80	)		2.62		482	%		0.45		—		—			—
Transportation and selling		1.42		125	%		0.63			2.36		—			2.36		2.44		23	%		1.98
Operating		5.42		-9	%		5.93			4.35		—			4.33		9.98		52	%		6.55

Netback	$	24.31				$	14.50		$	24.14				$	14.99	$	28.46				$	19.39

Crude Oil Sales Volumes (bbls per day)		142,506		-5	%		149,582			74,846		88	%		39,807		12,819		138	%		5,384

(1)

Excludes realized commodity and currency hedge activities.

NGLs ⁽¹⁾ ($ per barrel)


	Canada							United States							United Kingdom
	2004 vs							2004 vs							2004 vs
	2004		2003			2003		2004		2003			2003		2004		2003			2003
Price	$	33.46		42	%	$	23.52	$	36.09		42	%	$	25.50	$	25.82		38	%	$	18.69
Expenses
Production and mineral taxes		—		—			—		4.05		53	%		2.64		—		—			—
Transportation and selling		0.45		-22	%		0.58		—		—			—		0.44		-78	%		2.01

Netback	$	33.01				$	22.94	$	32.04				$	22.86	$	25.38				$	16.68

NGLs Sales Volumes (bbls per day)		12,804		-7	%		13,758		14,363		51	%		9,530		2,070		383	%		429

(1)

NGLs results includes Condensate.

- 11 -

Nine Months Ended September 30

Crude Oil ($ per barrel)


	North America							Ecuador							United Kingdom
	2004 vs							2004 vs							2004 vs
	2004		2003			2003		2004		2003			2003		2004		2003			2003
Price ⁽¹⁾	$	27.70		22	%	$	22.73	$	28.25		14	%	$	24.68	$	35.16		22	%	$	28.74
Expenses
Production and mineral taxes		0.35		—			—		1.93		9	%		1.77		—		—			—
Transportation and selling		1.36		8	%		1.26		2.30		-3	%		2.37		2.04		-4	%		2.13
Operating		5.29		-11	%		5.92		4.17		-16	%		4.99		7.08		61	%		4.41

Netback	$	20.70				$	15.55	$	19.85				$	15.55	$	26.04				$	22.20

Crude Oil Sales Volumes (bbls per day)		143,172		3	%		139,187		78,032		116	%		36,132		15,855		105	%		7,737

(1)

Excludes realized commodity and currency hedge activities.

NGLs ⁽¹⁾ ($ per barrel)


	Canada							United States							United Kingdom
	2004 vs							2004 vs							2004 vs
	2004		2003			2003		2004		2003			2003		2004		2003			2003
Price	$	29.65		24	%	$	23.99	$	34.15		26	%	$	27.07	$	23.79		15	%	$	20.69
Expenses
Production and mineral taxes		—		—			—		3.77		108	%		1.81		—		—			—
Transportation and selling		0.39		105	%		0.19		—		—			—		1.19		-20	%		1.49

Netback	$	29.26				$	23.80	$	30.38				$	25.26	$	22.60				$	19.20

NGLs Sales Volumes (bbls per day)		13,452		-8	%		14,591		12,126		31	%		9,230		2,035		180	%		726

(1)

NGLs results includes Condensate.

Increases in the average crude oil price, excluding the impact of financial hedges, in the third quarter and first nine months of 2004 reflect the increase in the benchmark West Texas Intermediate (“WTI”) and Dated Brent oil prices, offset partially by the increased applicable differentials compared to the same periods in 2003. Higher benchmark WTI crude oil prices of 45 percent in the quarter (27 percent year-to-date) for 2004 compared to the same periods in 2003 were partially offset by increased crude oil price differentials (up 49 percent in the third quarter and up 44 percent on a year-to-date basis) and a higher proportionate share of heavier blend oils in the product mix. Realized commodity and currency hedging losses on crude oil were approximately $221 million, or $9.28 per barrel of liquids in the third quarter of 2004 compared to a loss of approximately $44 million, or $2.18 per barrel of liquids in the third quarter 2003. On a year-to-date basis to September 30, realized commodity and currency hedging losses on crude oil were approximately $515 million, or $7.11 per barrel of liquids in 2004 compared to a loss of approximately $154 million, or $2.71 per barrel of liquids in 2003.

North American per unit production and mineral taxes increased in the third quarter and year-to-date primarily due to the impact of mineral tax amendments related to prior years that were recorded in the third quarter of 2003, which reduced mineral taxes by approximately $16 million or $0.42 per barrel on a year-to-date basis for 2003. This increase is offset slightly by the increased production weighting from properties that are not subject to production and mineral taxes combined with the disposition of several properties that were subject to production and mineral taxes. Per unit production and mineral taxes in Ecuador increased $2.17 per barrel in the third quarter of 2004 and $0.16 per barrel on a year-to-date basis over the same period of 2003 due to higher realized prices on the Tarapoa block volumes. The Company is required to pay the Ecuadorian government a percentage of revenue from this block based on realized prices over a base price.

Per unit crude oil transportation and selling costs in North America for the third quarter were higher by $0.79 per barrel over the same period of 2003. This is mainly due to a change in the method of allocating transportation between the Upstream and Midstream & Marketing segments which was revised during the third quarter of 2003 and a sales pipeline

- 12 -

break at Pelican Lake resulting in additional trucking charges and repair costs during the third quarter of 2004. On a year-to-date basis, the per unit crude oil transportation and selling expenses in North America have increased $0.10 per barrel mainly due to the higher U.S./Canadian exchange rates. Per unit transportation and selling costs in Ecuador for the nine months ended September 30, 2004 decreased as a result of lower net realized costs of operations of the OCP Pipeline.

North American crude oil per unit operating costs have decreased $0.51 per barrel in the third quarter and $0.63 per barrel on a year-to-date basis compared to the same periods in 2003. This is due to the sale of Petrovera which had relatively higher operating costs, as well as lower per unit fixed costs due to increased volumes offset partially by the increased U.S./Canadian exchange rates. In Ecuador, a significant portion of operating expenses are fixed, resulting in lower per unit operating expenses as sales volumes increased for the nine months ended September 30, 2004 compared to the same period in 2003. The third quarter crude oil per unit operating expenses in Ecuador has increased slightly due to higher workover costs during the quarter. The increase in the U.K.’s third quarter and year-to-date 2004 crude oil operating expenses is primarily related to platform turnaround, higher maintenance and fuel expenses and the U.S./U.K. exchange rates.

Midstream & Marketing Operations
Financial Results ($ millions)

Three Months Ended September 30


	Midstream								Marketing							Total
	2004 vs								2004 vs							2004 vs
	2004			2003			2003		2004		2003			2003		2004		2003			2003
Revenues	$	158			-12	%	$	180	$	731		22	%	$	601	$	889		14	%	$	781
Expenses
Transportation and selling		—			—			—		4		-64	%		11		4		-64	%		11
Operating		65			14	%		57		12		71	%		7		77		20	%		64
Purchased product		88			-21	%		112		712		23	%		580		800		16	%		692
Depreciation, depletion and amortization		8			14	%		7		—		—			2		8		-11	%		9

	$	(3	)				$	4	$	3				$	1	$	—				$	5

Nine Months Ended September 30


	Midstream								Marketing								Total
	2004 vs								2004 vs								2004 vs
	2004			2003			2003		2004		2003			2003			2004			2003			2003
Revenues	$	881			36	%	$	649	$	2,325		13	%	$	2,064		$	3,206			18	%	$	2,713
Expenses
Transportation and selling		—			—			—		20		-55	%		44			20			-55	%		44
Operating		192			2	%		188		32		-40	%		53			224			-7	%		241
Purchased product		655			55	%		423		2,254		14	%		1,983			2,909			21	%		2,406
Depreciation, depletion and amortization		58			222	%		18		2		-33	%		3			60			186	%		21

	$	(24	)				$	20	$	17				$	(19	)	$	(7	)				$	1

Revenues and purchased product expense in Midstream & Marketing operations increased in the third quarter and on a nine-month basis compared to the same periods in 2003 due primarily to increases in commodity prices. Decreases in transportation and selling costs in the third quarter and year-to-date to September 30, 2004 compared to the same periods in 2003 is primarily due to the reallocation of all natural gas downstream transportation costs to the Upstream segment.

- 13 -

Operating expenses in 2003 included a $20 million settlement with the U.S. Commodity Futures Trading Commission as described in the “Contractual Obligations and Contingencies” section of this MD&A which represents the primary reason for the decrease when comparing year-to-date results between 2003 and 2004.

The increase in year-to-date 2004 DD&A is primarily due to a write down in the value of the Company’s equity investment interest in the Trasandino Pipeline in Argentina and Chile of approximately $35 million.

Corporate


	Three Months Ended									Nine Months Ended
Corporate Items ($ millions)	September 30									September 30
				2004 vs									2004 vs
	2004			2003			2003			2004			2003			2003
Revenues, Net of Royalties	$	(501	)		—		$	1		$	(1,033	)		—		$	2
Expenses
Operating		1			—			—			(4	)		—			—
Depreciation, depletion and amortization		14			—			14			44			38	%		32
Administration		43			5	%		41			136			12	%		121
Interest, net		103			45	%		71			278			38	%		202
Accretion of asset retirement obligation		8			60	%		5			20			33	%		15
Foreign exchange gains		(288	)		1340	%		(20	)		(209	)		-52	%		(436	)
Stock-based compensation		5			-17	%		6			14			17	%		12
Gain on dispositions		—			—			—			(35	)		—			—
Income tax expense		77			-62	%		205			122			-64	%		342

Corporate revenues, net of royalties in the third quarter of 2004 include approximately $500 million in unrealized mark-to-market losses related to commodity contracts. On a year-to-date basis, revenues, net of royalties include mark-to-market losses on commodity contracts of approximately $1,035 million. Other mark-to-market gains ($7 million year-to-date) on derivative financial instruments related to interest and electricity consumption are recorded in the interest, net and operating expense account respectively.

Depreciation, depletion and amortization include provisions for corporate assets such as computer equipment, office furniture and leasehold improvements. The increase in expense on a year-to-date basis is the result of higher capital spending in prior periods on corporate capital items and the impact of the change in the U.S./Canadian dollar exchange rate.

The administrative expenses for the third quarter of 2004 compared to the same period in 2003 are relatively unchanged. The year-to-date results reflect the effect of the change in the U.S./Canadian dollar exchange rate and increased long-term compensation expenses. Administrative costs were lower by $0.10 per BOE, at $0.60 per BOE, for the third quarter of 2004 ($0.65 per BOE year-to-date) compared with $0.70 per BOE for the third quarter in 2003 ($0.70 per BOE year-to-date). Lower per unit administrative expenses are primarily as a result of the increase in sales volumes.

The higher interest expense resulted primarily from the higher average outstanding debt level as a result of the TBI acquisition in the second quarter and on a year-to-date basis for 2004 versus the same periods in 2003 and the impact of the change in the U.S./Canadian dollar exchange rate.

- 14 -

The majority of the foreign exchange gain of $288 million in the third quarter resulted from the change in the U.S./Canadian dollar period end exchange rate between June 30, 2004 and September 30, 2004 applied to U.S. dollar denominated debt issued in Canada as discussed previously in this MD&A. Under Canadian GAAP, the Company is required to translate long-term debt issued in Canada and denominated in U.S. dollars into Canadian dollars at the period-end exchange rate. Resulting foreign exchange gains or losses are recorded in the Consolidated Statement of Earnings.

The effective tax rate for the third quarter of 2004 was 16 percent compared to 42 percent for the same period in 2003 and 12 percent compared to 16 percent for 2003 on a year-to-date basis as disclosed in Note 8 to the Interim Consolidated Financial Statements. EnCana’s effective tax rate in any particular reporting period is a function of the relationship between the amount of net earnings before income taxes for the period and the magnitude of the items representing “permanent differences” that are excluded from the calculation of earnings for the period that will be subject to tax. There are a variety of items of this type, including:

•

The non-taxable half of Canadian capital gains (losses);

•

Adjustments for the impact of legislative changes which have a prospective impact on future income tax obligations;

•

The effects of asset dispositions where the tax values of the assets sold differ from the accounting value; and

•

Items such as resource allowance, non-deductible crown payments and some marked to market adjustments where the treatment is different for income tax and accounting purposes.

Given the nature and scale of EnCana’s activities, it is difficult to forecast the magnitude and timing of these types of items.

EnCana sold oil and gas interests in a manner which resulted in the retention of certain associated tax basis resulting in a reduction to the tax provision for the third quarter in 2004 of $59 million and $162 million for year-to-date 2004.

Current income tax expense for the third quarter of 2004 was $124 million compared to $51 million for the same period in 2003. Current taxes were expected to increase significantly in 2004 when compared to the prior year as the effects of the merger with Alberta Energy Company Ltd. (“AEC”) were reflected in the Company’s tax position for 2003.

The operations of the Company are complex and related tax interpretations, regulations and legislation in the various jurisdictions that the Company and its subsidiaries operate in are continually changing. As a result, there are usually some tax matters under review. The Company believes that the provision for taxes is adequate.

- 15 -

CAPITAL EXPENDITURES

Capital Investment


	Three Months Ended September 30								Nine Months Ended September 30
				2004 vs								2004 vs
($ millions)	2004			2003			2003		2004			2003			2003
Upstream
Canada	$	598			-33	%	$	897	$	2,282			9	%	$	2,096
United States		325			16	%		279		851			38	%		615
Ecuador		53			-18	%		65		163			-5	%		172
United Kingdom		82			332	%		19		290			544	%		45
Other Countries		15			—			15		49			-22	%		63

Total Upstream	$	1,073			-16	%	$	1,275	$	3,635			22	%	$	2,991
Midstream & Marketing		15			-74	%		58		40			-74	%		154
Corporate		10			43	%		7		28			-26	%		38

Core Capital Expenditures	$	1,098			-18	%	$	1,340	$	3,703			16	%	$	3,183
Acquisition of Tom Brown, Inc.⁽¹⁾		—			—			—		2,335			—			—
Acquisitions⁽²⁾		49			-49	%		96		189			-59	%		462
Dispositions⁽³⁾		(940	)		—			—		(1,359	)		—			(19	)

Net Capital Expenditures⁽⁴⁾	$	207			-86	%	$	1,436	$	4,868			34	%	$	3,626

(1)		Excludes approximately $406 million of TBI acquired debt.

(2)		Represents Corporate acquisitions and property acquisitions.

(3)

The Petrovera acquisition of $253 million and subsequent disposition for $540 million has been included on a net basis in dispositions in the first quarter of 2004.

(4)

Excludes discontinued operations.

The Company’s core capital expenditures for the third quarter of 2004 were offset significantly by non-core asset dispositions that were discussed in the second quarter MD&A. The increase in Upstream core capital expenditures for the nine month period in 2004 compared to the same period in 2003 was primarily as a result of continued development of EnCana’s North American resource play properties. Net capital expenditures increased approximately $1.2 billion for the nine months ended September 30, 2004 compared to the same period in 2003 as a result of the TBI acquisition, higher levels of operating activity in Upstream, and the impact of the higher U.S./Canadian dollar exchange rate partially offset by $1.4 billion in non-core asset dispositions. The Company’s capital investment was funded by cash flow in excess of amounts paid for purchases under the Normal Course Issuer Bid, proceeds received on dispositions of non-core assets as well as debt.

Upstream Capital Expenditures

The decreases in Upstream capital expenditures in the third quarter compared to the same quarter in 2003 is largely attributable to the September 2003 land acquisitions at Cutbank Ridge. The increase in Upstream capital expenditures on a year-to-date basis in 2004 compared to the same period in 2003 reflect increased drilling and development activities and the impact of the increased average U.S./Canadian dollar exchange rate on Canadian dollar denominated expenditures. On a year-to-date basis the change in the average U.S./Canadian dollar exchange rate resulted in an increase on Canadian dollar denominated capital expenditures of approximately $168 million. Capital spending was primarily focused on North American resource play properties with spending in Canada directed mostly at natural gas and oil exploration and

- 16 -

development of properties on the Suffield and Palliser Blocks in southeast Alberta, as well as Greater Sierra and Cutbank Ridge in northeast British Columbia and Pelican Lake in northeast Alberta. The majority of capital expenditures in the U.S. were directed towards drilling in Mamm Creek, Jonah and Texas. Capital expenditures in the U.K. primarily reflect activity related to the development of the Buzzard field. The Company drilled 3,998 net wells year-to-date September 30, 2004 compared to 4,113 net wells in the same period of 2003.

Midstream & Marketing Capital Expenditures

Capital expenditures in Midstream & Marketing relate primarily to improvements to midstream facilities and various development initiatives. Expenditure levels were significantly higher in 2003 due to the expansion of the gas storage business and the buyout of equipment operating leases.

Corporate Capital Expenditures

Corporate capital expenditures relate primarily to spending on business information systems, leasehold improvements and furniture and office equipment.

Acquisitions and Divestitures

During the third quarter of 2004, the Company disposed of various non-core properties in North America for proceeds of approximately $940 million as disclosed previously in the second quarter MD&A. Total dispositions for the nine months ended September 30, 2004 are approximately $1.4 billion.

Other major acquisitions and divestitures completed and disclosed in the first two quarters of 2004 include the TBI acquisition for approximately $2.7 billion including $0.4 billion in acquired debt; the acquisition of additional interests in the Scott and Telford fields in the U.K. for approximately $112 million; and the disposition of the Company’s interest in the Petrovera Partnership for approximately $287 million.

LIQUIDITY AND CAPITAL RESOURCES

EnCana’s cash flow from continuing operations was $1,363 million for the three months ended September 30, 2004, up $390 million compared to the same period last year and on a year-to-date basis was $3,489 million for the period ended September 30, 2004, up $286 million compared to the same nine-month period in 2003. The increase in cash flows in the quarter and on a year-to-date basis were primarily due to increased revenues from the growth in sales volumes, higher commodity prices offset by higher realized commodity hedging losses, an increase in the current tax provision and an increase in the U.S./Canadian dollar exchange rate.

During the third quarter of 2004, long-term debt plus the current portion of long-term debt decreased $729 million compared to the previous quarter ended June 30, 2004 as a result of the dispositions and increase in cash flows. EnCana’s net debt adjusted for working capital was $9,014 million as at September 30, 2004 compared with $5,931 million at December 31, 2003. Working capital was a deficit of $978 million at September 30, 2004 and included unrealized losses on mark-to-market accounting on derivatives of $674 million and a current tax payable of $526 million. This compares to a working capital surplus of $157 million as at December 31, 2003. Cash flow together with proceeds from dispositions was used for the purchase of shares under the Company’s Normal Course Issuer Bid and capital expenditures. As a result of these activities, long-term debt plus the current portion of long-term debt increased $2,211 million as at September 30, 2004 compared to the 2003 year-end.

Net debt to capitalization was 43 percent as of September 30, 2004, up from 34 percent at December 31, 2003, primarily as a result of the acquisition of TBI and the impact of mark-to-market accounting on derivatives. Management calculates this ratio for internal purposes to steward the Company’s overall debt position as a measure of a company’s financial strength.

- 17 -

EnCana’s long term credit ratings were confirmed by all its credit rating agencies by the end of the third quarter. Standard & Poor’s has affirmed an A- with a ‘Negative Outlook’, Dominion Bond Rating Services has affirmed an A(low) with a ‘Negative Trend’ and Moody’s lowered EnCana’s rating to Baa2 Stable. The agencies are expected to continue to monitor the Company’s operating and financial performance through the year end.

On July 29, EnCana made a public offering in the United States for $250 million notes due in 2009 at 4.60 percent and $750 million notes due in 2034 at 6.50 percent. The proceeds from these issues were used primarily to repay existing bank and commercial paper indebtedness.

In September 2004, EnCana filed a multi-jurisdictional shelf prospectus whereby it may issue from time to time up to $2 billion of debt securities. This shelf prospectus replaced EnCana’s previous $2 billion U.S. debt shelf prospectus which expired on September 22, 2004. No amounts have been issued under the new shelf prospectus.

On August 9, 2004, EnCana redeemed all of its 8.50% Unsecured Junior Subordinated Debentures due 2048, which had an aggregate principal amount of C$200 million, at par plus accrued interest. On September 30, 2004, EnCana redeemed all of its 9.50% Preferred Securities due 2048, which had an aggregate principal amount of $150 million, at par.

As at September 30, 2004, the Company had available unused committed bank credit facilities in the amount of $1,865 million.

In October 2003, EnCana received approval from the Toronto Stock Exchange to continue to purchase, for cancellation, Common Shares under a Normal Course Issuer Bid (the “Bid”). Under the Bid, EnCana was entitled to purchase for cancellation up to 23.2 million of its Common Shares over a 12-month period ending October 21, 2004. In the third quarter of 2004, EnCana did not purchase any of its shares under the Bid. On a year-to-date basis, EnCana purchased for cancellation approximately 5.5 million of its shares at an average price of C$55.37 per share. From the inception of this Bid in October 2003 through its expiry in October 2004, the Company had purchased for cancellation approximately 9.1 million Common Shares at an average price of C$51.56 per share.

On October 26, 2004 the Company received Toronto Stock Exchange approval for a new Normal Course Issuer Bid commencing October 29, 2004 for a twelve month period. Under this bid, EnCana will be able to purchase for cancellation up to 23.1 million of its Common Shares, representing five percent of the approximately 462 million Common Shares outstanding as of October 15, 2004.

BUSINESS ENVIRONMENT

Natural Gas


	Three Months Ended							Nine Months Ended							Year
	September 30							September 30							Ended
Natural Gas Price Benchmarks			2004 vs							2004 vs
(Average for the period)	2004		2003			2003		2004		2003			2003		2003
AECO Price (C$/Mcf)	$	6.66		6	%	$	6.29	$	6.69		-5	%	$	7.07	$	6.70
NYMEX Price ($/MMBtu)		5.76		16	%		4.97		5.81		3	%		5.66		5.39
Rockies (Opal) Price ($/MMBtu)		5.06		16	%		4.37		5.02		22	%		4.10		4.12
AECO/NYMEX Basis Differential ($/MMBtu)		0.70		84	%		0.38		0.78		5	%		0.74		0.65
Rockies/NYMEX Basis ($/MMBtu)		0.70		17	%		0.60		0.80		-49	%		1.56		1.27

Concerns that North American natural gas supply will not be able to meet increasing demands and the influence of high crude oil prices have continued to result in historically high average NYMEX gas prices. Lower average AECO gas prices on a year-to-date basis in 2004 can be attributed to wider differentials from NYMEX in the third quarter combined with the appreciation of the U.S./Canadian dollar exchange rate. The increased AECO/NYMEX basis differential in the third quarter of 2004 compared to the third quarter of 2003 can be attributed to increased transportation differentials for the marginal sales volumes transported from Alberta to Eastern Canada.

- 18 -

Percentage of Natural Gas Volumes Benchmark Price Exposure
(Annual approximate percentage)

Crude Oil


	Three Months Ended							Nine Months Ended							Year
	September 30							September 30							Ended
Crude Oil Price Benchmarks			2004 vs							2004 vs
(Average for the period U.S.$/bbl)	2004		2003			2003		2004		2003			2003		2003
WTI		43.89		45	%		30.21		39.21		27	%		30.94		30.99
Dated Brent		41.54		46	%		28.41		36.28		27	%		28.65		28.84
WTI/Bow River Differential		12.09		49	%		8.12		10.72		44	%		7.42		8.01
WTI/OCP NAPO Differential (Ecuador)⁽¹⁾		14.31		85	%		7.75		12.71		64	%		7.75		8.06
WTI/Oriente Differential (Ecuador)		11.63		118	%		5.34		9.07		63	%		5.57		5.59

(1)

The WTI/OCP NAPO Differential was posted as of September 2003.

		Continued increased demand in Asia and North America along with supply uncertainties in the Middle East as well as west Africa and recent damage to production platforms in the Gulf of Mexico has caused the WTI crude oil price to be significantly higher in the third quarter and on a year-to-date basis in 2004 when compared to the corresponding periods in 2003.

		The Canadian WTI/Bow River heavy oil differential widened in the third quarter of 2004 compared to the third quarter of 2003 primarily due to the higher price for WTI, as well as wider U.S. Gulf Coast light to heavy product differentials. As a percentage of WTI, Bow River’s average sales price for the third quarter of 2004 was 72 percent of WTI as compared to 73 percent in the third quarter of 2003. On a year-to-date basis, Canadian WTI/Bow River heavy oil differential was higher primarily as a result of the increase in WTI.

		The Company currently transports nearly all of its Ecuadorian production through the OCP Pipeline as NAPO blend. NAPO blend is a heavier crude than the SOTE Oriente blend, previously the predominant crude oil from Ecuador, resulting in a wider differential to WTI. The third quarter and year-to-date 2004 increases in the Oriente differential compared to the same periods in 2003 are primarily related to the increase in the WTI price as well as wider U.S. Gulf Coast light to heavy product differentials.

- 19 -

U.S./Canadian Dollar Exchange Rates

Three Months Ended

Nine Months Ended

Year

September 30

Ended

Foreign Exchange Benchmarks

2004 vs

(Average for the period)

2004

2003

2004

2003

U.S./Canadian Dollar Period-End Exchange Rate

0.791

0.741

0.791

0.741

0.774

U.S./Canadian Dollar Average Exchange Rate

0.765

0.725

0.753

0.701

0.716

The third quarter 2004 over third quarter 2003 average U.S./Canadian dollar exchange rate increase was primarily the result of the economic slowdown in the U.S., continuing differences between Canadian and U.S. interest rates and the U.S. current account deficit.

OUTSTANDING SHARE DATA

The Company is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares. As at September 30, 2004, there were 462 million Common Shares outstanding compared to 465 million Common Shares outstanding at September 30, 2003 and 461 million Common Shares outstanding as at December 31, 2003. There were no Preferred Shares outstanding as at September 30, 2004 or September 30, 2003.

Employees and directors have been granted options to purchase Common Shares under various plans. During the third quarter of 2004, approximately 1.0 million Common Shares were issued (year-to-date approximately 6.9 million Common Shares) under the terms of these plans. These plans and outstanding balances are disclosed in Note 11 to the Interim Consolidated Financial Statements.

As discussed previously in the Liquidity and Capital Resources section of this MD&A, the Company did not repurchase any of its Common Shares during the third quarter. The Company has repurchased for cancellation 5.5 million Common Shares at an average price of C$55.37 in the first nine months of 2004 under a Normal Course Issuer Bid that was approved by the Toronto Stock Exchange in October 2003.

CONTRACTUAL OBLIGATIONS AND CONTINGENCIES

The Company has entered into various commitments primarily related to debt, demand charges on firm transportation agreements, capital commitments and marketing agreements. In addition, the Company has made commitments related to the risk mitigation program and has incurred additional commitments as a result of the TBI acquisition. See Note 14 of the Interim Consolidated Financial Statements for the financial transactions and the “Risk Management” section of this MD&A for a discussion of the physical contracts.

Included in the long-term debt commitments, the Company had $2,446 million outstanding as at September 30, 2004 related to Banker’s Acceptances, Commercial Paper and LIBOR loans that are supported by revolving credit facilities and term loan borrowings. Approximately $846 million of this amount is related to the bridge credit facility which was put in place to finance a portion of the TBI acquisition and is required to be reduced to $450 million principal outstanding by August 2005 and repaid in its entirety by May 2006. With respect to the balance of the outstanding revolving credit facilities and term loan borrowings of approximately $1,600 million, the Company intends and expects that it will have the ability to extend the term on an ongoing basis. Further details regarding the Company’s long-term debt are described in Note 9 to the Interim Consolidated Financial Statements.

As at September 30, 2004, EnCana had entered into long-term, fixed price, physical contracts with a current delivery of approximately 48 MMcf per day with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 172 billion cubic feet at a weighted average price of $3.55 per Mcf. At September 30, 2004, these transactions had an unrealized loss of $177 million.

- 20 -

A subsidiary of the Company in Ecuador has a 40 percent economic interest in relation to Block 15 pursuant to a contract with a third party. The state oil company of Ecuador has formally notified the third party of a contractual dispute which is disclosed in Note 15 of the Interim Consolidated Financial Statements.

In addition to the above, the Company is proceeding with its arbitration related to value added tax and is in discussions related to certain income tax matters related to interest deductibility in Ecuador.

Legal Proceedings Related to Discontinued Merchant Energy Operations

In July 2003, the Company’s indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. (“WD”), concluded a settlement with the U.S. Commodity Futures Trading Commission (“CFTC”) of a previously disclosed CFTC investigation. The investigation related to alleged inaccurate reporting of natural gas trading information during 2000 and 2001 by former employees of WD’s now discontinued Houston-based merchant energy trading operation to energy industry publications that compiled and reported index prices. All Houston-based merchant energy trading operations were discontinued following the merger with AEC in 2002. Under the terms of the settlement, WD agreed to pay a civil monetary penalty in the amount of $20 million without admitting or denying the findings in the CFTC’s order.

The Company and WD are defendants in a lawsuit filed by E. & J. Gallo Winery in the United States District Court in California and, along with other energy companies, are defendants in several other lawsuits in California (many of which are class actions) and three class action lawsuits filed in the United States District Court in New York. A motion by the Company and WD to dismiss the Gallo complaint on the basis that the Federal Energy Regulatory Commission had exclusive jurisdiction regarding this matter was not granted. Most of the California class action lawsuits were transferred by the Judicial Panel on Multidistrict Litigation on a consolidated basis to the Nevada District Court and all of the New York lawsuits were consolidated in New York District Court by the plaintiff’s application. The California lawsuits relate to sales of natural gas in California from 1999 to the present and contain allegations that the defendants engaged in a conspiracy with unnamed competitors in the natural gas and derivatives market in California in violation of U.S. and California anti-trust and unfair competition laws to artificially raise the price of natural gas through various means including the illegal sharing of price information through online trading, price indices and wash trading. The New York lawsuits claim that the defendants’ alleged manipulation of natural gas price indices resulted in higher prices of natural gas futures and option contracts traded on the NYMEX from 2000 to 2002. EnCana Corporation has been dismissed from the New York lawsuits, leaving only WD as a defendant. The Gallo complaint claims damages in excess of $30 million, before potential trebling under California laws. As is customary, none of the other actions specify the amount of damages claimed.

The Company and WD intend to vigorously defend against these 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.

ACCOUNTING POLICIES AND ESTIMATES

Changes in Accounting Principles and Practices

Hedging Relationships

On January 1, 2004, the Company adopted the amendments made to the accounting standard for Hedging Relationships. Derivative instruments outstanding at January 1, 2004, that did not qualify as a hedge or were not designated as a hedge, were recorded using the mark-to-market accounting method whereby their fair value was recorded on the Consolidated Balance Sheet. The impact on the Company’s Consolidated Financial Statements at January 1, 2004 was an increase in assets of $145 million, an increase in liabilities of $380 million and a net deferred loss of $235 million. These amounts are taken into net earnings as the contracts expire. At September 30, 2004, approximately $242 million of these net losses were recognized. The timing of recognition of the remaining net gains of $7 million ($5 million after-tax) is described in Note 2 of the Interim Consolidated Financial Statements.

- 21 -

Changes in the fair value from June 30, 2004 to September 30, 2004 for these contracts, as well as all other outstanding hedge contracts, were marked-to-market and a $497 million loss ($321 million after-tax) was recognized in net earnings for the three months ended September 30, 2004. All unrealized losses on derivative instruments as at September 30, 2004 are disclosed in Note 14 of the Interim Consolidated Financial Statements.

RISK MANAGEMENT

EnCana’s results are impacted by external market risks associated with fluctuations in commodity prices, foreign exchange rates and interest rates in addition to credit, operational and safety and environmental risks.

Commodity Prices

The Company partially mitigates its exposure to market risks through the use of various financial instruments and physical contracts. The use of derivative instruments is governed under formal policies approved by senior management, and is subject to limits established by the Board of Directors. As a means of mitigating market price risk associated with cash flows expected to be generated from budgeted capital programs and in other cases to the mitigation of market price risks for specific assets and obligations the Company has entered into various financial instrument agreements for both natural gas and crude oil as disclosed in Note 14 of the Interim Consolidated Financial Statements. As at September 30, 2004, EnCana has fixed price physical contracts of approximately 48 MMcf per day and various physical Rockies natural gas basis contracts with varying terms and volumes through 2007. At September 30, 2004, these transactions had an unrealized loss of approximately $17 million.

Other Risks

Other risks are partially mitigated through comprehensive insurance programs or managed by executing policies and standards that comply or exceed government regulations and industry standards. The Company also partially mitigates risks such as land access through communication and negotiation with individuals and communities in which it operates. Environmental risks such as the Kyoto Accord and similar initiatives in the U.S.A. remain unchanged as discussed in the 2003 year-end MD&A.

OUTLOOK

EnCana plans to focus primarily on exploitation of its North American resource plays to grow natural gas and crude oil production. The Company also has substantial assets in the Gulf of Mexico, Canadian East Coast, the U.K. central North Sea and Ecuador. The Company also plans to continue its focused, high-upside North American and international exploration programs.

The Company expects its 2004 core capital investment program to be between $4,700 million and $5,000 million and funded from cash flow and proceeds from divestitures of non-core assets.

Sales volume guidance for 2004 was increased in the second quarter and represents an approximate 15 percent growth over 2003 full year sales volumes (based on the midpoint of guidance). Included in the increased guidance is a 12 percent organic growth rate from the Company’s inventory of resource plays and international assets. The guidance range for sales volumes was increased in June 2004 to reflect the strong operating performance from the Company’s resource play assets in North America year-to-date.

Operating and Administrative Expenses

Total operating costs for 2004 are expected to range between $3.30 and $3.50 per BOE with administrative expense between $0.60 and $0.70 per BOE.

- 22 -

Current Income Taxes

At the date hereof, based on First Call consensus commodity pricing, for the balance of the year and production and capital expenditure estimates based on the mid-point of public guidance, EnCana expects the 2004 provision for current income taxes will be within the guidance range of $675 million to $820 million.

- 23 -

NOTE REGARDING FORWARD-LOOKING STATEMENTS

In the interest of providing EnCana shareholders and potential investors with information regarding the Company and its subsidiaries, certain statements throughout this MD&A constitute forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to: production and sales estimates for crude oil, natural gas and NGLs for 2004 and beyond; the Company’s plans to focus on exploitation of its resource plays and international exploitation projects to grow production of oil and natural gas; amounts which may be issued under the Company’s multi-jurisdictional shelf prospectus program; the Company’s projected capital investment levels for 2004 and the source of funding therefor; the effect of the Company’s risk management program, including the impact of derivative financial instruments; the Company’s execution of share purchases under its Normal Course Issuer Bid; the Company’s defence of lawsuits; the Company’s projected ability to extend its debt program on an ongoing basis; projected operating and administrative costs for 2004; the impact of the Kyoto Accord and similar initiatives in the U.S.A. on operating costs; projected tax rates and projected current taxes payable for 2004 and 2005 and the adequacy of the Company’s provision for taxes; and rating agency monitoring and reviews which may occur in the future.

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 oil and gas prices; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the Company’s and its subsidiaries’ marketing operations, including credit risks; imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved; the Company’s and its subsidiaries’ 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; 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 and its subsidiaries’ ability to secure adequate product transportation; changes in environmental and other regulations; political and economic conditions in the countries in which the Company and its subsidiaries’ operate, including Ecuador; the risk of international war, hostilities, civil insurrection and instability affecting countries in which the Company and its subsidiaries operate and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions brought against the Company and its subsidiaries; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Statements relating to “reserves” or “resources” or “resource potential” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. 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 MD&A are made as of the date of this MD&A, and 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 MD&A are expressly qualified by this cautionary statement.

NOTE REGARDING 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

- 24 -

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”). The reserves quantities disclosed by EnCana 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.

Natural Gas Conversions

Natural gas volumes that have been converted to barrels of oil equivalent (“BOE(s)”) have been converted on the basis of six thousand cubic feet (“Mcf”) to one barrel (“Bbl”). BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent equivalency at the well head. Natural gas volumes are also often presented in million cubic feet (“MMcf”). Natural gas volumes are sold based on heat content in British Thermal Units (“Btu’s”) but physically measured in standard cubic feet (“scf”). The heat content of natural gas varies by formation and therefore by production region. For example, the heat content of EnCana’s natural gas production in Alberta is approximately 1,020 Btu/scf and the U.S. Rockies is approximately 1,110 Btu/scf. The average heat content of EnCana’s natural gas production in total is approximately 1,040 Btu/scf or 1.04 million British Thermal Units (“MMBtu”)/Mcf.

Resource Play, Estimated Ultimate Recovery and Resource Potential

EnCana uses the terms resource play, estimated ultimate recovery and resource potential. 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. As used by EnCana, estimated ultimate recovery has the meaning set out jointly by the Society of Petroleum Engineers and World Petroleum Congress in the year 2000, being those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom. Resource potential is a term used by EnCana to refer to the estimated quantities of hydrocarbons that may be added to proved reserves over a specified period of time largely from a specified resource play or plays. EnCana’s current stated estimates of unbooked resource potential utilize a five year time frame for their specified period of time.

NOTE REGARDING CURRENCY, PROTOCOLS NON-GAAP MEASURES AND REFERENCES TO ENCANA

All information included in this MD&A and the Interim Consolidated Financial Statements and comparative information is shown on a U.S. dollar, after-royalties basis unless otherwise noted. Sales forecasts reflect the mid-point of current public guidance on an after royalties basis. Current Corporate Guidance assumes a U.S. dollar exchange rate of $0.73 for every Canadian dollar.

Non-GAAP Measures

Certain measures in this MD&A do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles (“Canadian GAAP”) such as Cash Flow from Continuing Operations, Cash Flow, Cash Flow from Continuing Operations per share-basic, Cash Flow from Continuing Operations per share-diluted, Cash Flow per share-basic and Cash Flow per share-diluted, Operating Earnings and Operating Earnings per share-diluted and therefore are considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this MD&A in order to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Management’s use of these measures has been disclosed further in this MD&A as these measures are discussed and presented.

References To EnCana

For convenience, references in this MD&A to “EnCana”, the “Company”, “we”, “us” and “our” 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.

October 26, 2004

- 25 -

(ENCANA LOGO)


		EnCana Corporation
		EnCana on 8^th		tel:(403)645-2000
		1800 855 2^nd Street SW
		PO Box 2850
		Calgary AB Canada T2P 2S5		www.encana.com

October 27, 2004

British Columbia Securities Commission
Alberta Securities Commission
Saskatchewan Securities Commission
The Manitoba Securities Commission
Ontario Securities Commission
Autorité des marchés financiers
New Brunswick Office of the Administrator of Securities
Prince Edward Island Securities Office
Nova Scotia Securities Commission
Newfoundland Department of Government Services and Lands, Securities Division
Registrar of Securities, Northwest Territories
Registrar of Securities, Yukon Territory
Registrar of Securities, Nunavut Territory
The Toronto Stock Exchange

Dear Sirs:

Re: EnCana Corporation (“EnCana”) – Interim Report for the period ended September 30, 2004

This filing is being done in accordance with the continuous filing obligations of National Instrument 44-102 of the Canadian Securities Administrators arising from the following documents which were filed with the securities regulatory authorities across Canada:

a)		EnCana’s Medium Term Note program in respect of which a Short Form Shelf Prospectus dated August 20, 2003 relating to the offering of Medium Term Notes in an aggregate principal amount of up to $1.0 billion (SEDAR project no. 00562373);

b)		EnCana’s debt securities program in respect of which a Short Form Shelf Prospectus dated September 16, 2004 relating to the offering of debt securities in an aggregate principal amount of up to US$2.0 billion debt securities (SEDAR project no. 00686926); and

c)		EnCana Holdings Finance Corp.’s U.S. debt securities program in respect of which a Short Form Shelf Prospectus dated March 26, 2004, relating to the offering of debt securities (guaranteed by EnCana) in an aggregate principal amount of up to US$2.0 billion debt securities (SEDAR project no. 00622960).

Consolidated Financial Ratios, provided in connection with EnCana’s continuous offering of medium term notes and debt securities, and a comfort letter from PricewaterhouseCoopers LLP, in respect of the unaudited Consolidated Financial Statements for the period ended September 30, 2004, have been filed under the SEDAR project number for the said interim financial statements.

Yours truly,

ENCANA CORPORATION

[signed] Kerry D. Dyte

KERRY D. DYTE
Corporate Secretary

(PRICEWATERHOUSECOOPERS LOGO)


		PricewaterhouseCoopers LLP
		Chartered Accountants
		111 5th Avenue SW, Suite 3100
		Calgary, Alberta
		Canada T2P 5L3
October 27, 2004		Telephone +1 (403) 509 7500
		Facsimile +1 (403) 781 1825
		Direct Tel. (403) 509-7500
		Direct Fax (403) 781-1825

British Columbia Securities Commission
Alberta Securities Commission
Saskatchewan Securities Commission
Manitoba Securities Commission
Ontario Securities Commission
Autorité des marchés financiers
New Brunswick Securities Administration Branch
Nova Scotia Securities Commission
Prince Edward Island Securities Office
Securities Commission of Newfoundland and Labrador
Registrar of Securities, Northwest Territories Registrar of Securities
Registrar of Securities, Yukon
Registrar of Securities, Nunavut

Re: EnCana Corporation (“EnCana”) – Interim Financial Statements

We refer to the base shelf short form prospectus of EnCana dated August 20, 2003, relating to the sale and issue of up to $1,000,000,000 of Medium Term Notes and the base shelf short form prospectus of EnCana Holdings Finance Corp., an indirect wholly owned subsidiary of EnCana, dated March 26, 2004, relating to the sale and issue of up to U.S. $2,000,000,000 in debt securities guaranteed by EnCana and the base shelf short form prospectus of EnCana dated September 16, 2004 relating to the sale and issue of up to U.S. $2,000,000,000 in debt securities and (collectively, the “Prospectuses”).

The Prospectuses now also incorporate by reference the following unaudited interim consolidated financial statements of EnCana:

Consolidated balance sheet as at September 30, 2004; and
Consolidated statements of earnings and cash flows for the three and nine month periods ended September 30, 2004 and 2003 and the consolidated statement of retained earnings for the nine month periods ended September 30, 2004 and 2003.

PricewaterhouseCoopers refers to the Canadian firm of pricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entry.

(PRICEWATERHOUSECOOPERS LOGO)

We have not audited any financial statements of the Company as at any date or for any period subsequent to December 31, 2003. Although we have performed an audit for the year ended December 31, 2003, the purpose and therefore the scope of the audit was to enable us to express our opinion on the financial statements as at December 31, 2003 and for the year then ended, but not on the financial statements for any interim period within that year.

Therefore, we are unable to and do not express opinions on the unaudited interim consolidated financial statements, or on the financial position, results of operations or cash flows of the Company as at any date or for any period subsequent to December 31, 2003.

We have, however, performed a review of the unaudited interim financial statements of the Company for the three and nine month periods ended September 30, 2004 and 2003. We performed our review in accordance with Canadian generally accepted standards for a review of interim financial statements by an entity’s auditors. Such an interim review consists principally of applying analytical procedures to financial data, and making enquiries of, and having discussions with, persons responsible for financial and accounting matters. An interim review does not provide assurance that we would become aware of any or all significant matters that might be identified in an audit.

Based on our review, we are not aware of any material modification that needs to be made for these interim financial statements to be in accordance with Canadian generally accepted accounting principles.

This letter is provided solely for the purpose of assisting the securities regulatory authorities to which it is addressed in discharging their responsibilities and should not be used for any other purpose. Any use that a third party makes of this letter, or any reliance or decisions made based on it, are the responsibility of such third parties. We accept no responsibility for loss, or damages, if any, suffered by any third party as a result of decisions made or actions taken based on this letter.

Yours very truly,

signed (“PricewaterhouseCoopers LLP”)

Chartered Accountants

(2)

EnCana Corporation
Supplemental Financial Information (unaudited)
Exhibit to September 30, 2004 Consolidated Financial Statements

CONSOLIDATED FINANCIAL RATIOS - MEDIUM TERM NOTES & DEBT SECURITIES

The following ratios, based on the consolidated financial statements, are provided in connection with the Company’s continuous offering of medium-term notes and debt securities and are for the 12-month period then ended.


	September 30
	2004		2003
			Restated
Interest coverage on long-term debt:
Net earnings		5.5		10.1
Cash flow		15.8		14.5


Note:	The Company has retroactively adopted the amendment made to the Canadian Institute of Chartered Accountants Handbook section 3860 “Financial Instruments - Disclosure and Presentation”. As a result, the preferred securities issued by the Company are now recorded as a liability and included in long-term debt and the related carrying charges have been included as interest expense.

(ENCANA LOGO)

Form 52-109FT2
Certification of Interim Filings during Transition Period

I, Gwyn Morgan, President & Chief Executive Officer of EnCana Corporation, certify that:

1.		I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings) of EnCana Corporation (the issuer) for the interim period ending September 30, 2004;

2.		Based on my knowledge, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings; and

3.		Based on my knowledge, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the interim filings.

Date: October 26, 2004


		/s/ “Gwyn Morgan”

		Gwyn Morgan
		President & Chief Executive Officer

(ENCANA LOGO)

Form 52-109FT2
Certification of Interim Filings during Transition Period

I, John D. Watson, Executive Vice-President & Chief Financial Officer of EnCana Corporation, certify that:

1.		I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings) of EnCana Corporation (the issuer) for the interim period ending September 30, 2004;

2.		Based on my knowledge, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings; and

3.		Based on my knowledge, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the interim filings.

Date: October 26, 2004


		/s/ “John D. Watson”

		John D. Watson
		Executive Vice-President &
		Chief Financial Officer