SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

For: November 5, 2002

ALBERTA ENERGY COMPANY LTD.

(Translation of registrant’s name into English)

1800, 855 – 2nd Street S.W. PO Box 2850
Calgary, Alberta, Canada T2P 2S5

(Address of principal executive offices)

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

Form 20-F  o Form 40-F  x

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

Yes  o No  x

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

TABLE OF CONTENTS

Consolidated Financial Statements
For the period ended September 30, 2002

Alberta Energy Company Ltd.

(a wholly owned subsidiary of EnCana Corporation)

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Consolidated Statement of Earnings

			September 30
			Three Months Ended					Nine Months Ended
(unaudited) ($ millions)			2002		2001			2002			2001
Revenues, Net of Royalties and Production Taxes		(note 3)	$	1,782	$	1,299		$	4,339		$	4,949
Expenses		(note 3)
	Transportation and selling			127		95			334			272
	Operating			221		199			661			625
	Purchased product			755		540			1,610			1,933
	Administrative			31		20			75			53
	Interest, net			87		57			229			154
	Foreign exchange			71		79			(15	)		98
	Depreciation, depletion and amortization			333		289			1,047			856
	Loss (gain) on sale of assets			—		(166	)		22			(166	)
				1,625		1,113			3,963			3,825
Net Earnings Before the Undernoted				157		186			376			1,124
	Income tax expense	(note 6)		55		40			152			390
	Non-controlling interest	(note 5)		9		—			8			—
Net Earnings from Continuing Operations				93		146			216			734
Non-Controlling Interest from Discontinued Operations				5		—			2			—
Net Earnings from Discontinued Operations		(note 4)		20		—			29			10
Net Earnings				108		146			243			744
Distributions on Preferred Securities, Net of Tax				11		10			27			31
Net Earnings Attributable to Common Shareholders			$	97	$	136		$	216		$	713

Consolidated Statement of Retained Earnings

			September 30
			Nine Months Ended
(unaudited) ($ millions)			2002			2001
Retained Earnings, Beginning of Year
	As previously reported		$	1,788		$	1,264
	Retroactive adjustment for change in accounting policy	(note 2)		—			(29	)
	As Restated			1,788			1,235
Charges for Normal Course Issuer Bid				(15	)		(136	)
Net Earnings				243			744
Dividends on Common Shares				(66	)		(90	)
Distributions on Preferred Securities, Net of Tax				(27	)		(31	)
Retained Earnings, End of Period			$	1,923		$	1,722

See accompanying notes to Consolidated Financial Statements

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Consolidated Balance Sheet

			As at		As at
			September 30		December 31
(unaudited) ($ millions)			2002		2001
Assets
Current Assets
	Cash and cash equivalents		$	239	$	56
	Accounts receivable and accrued revenue			1,313		935
	Income tax receivable			259		—
	Inventories			471		320
				2,282		1,311
Capital Assets, net				13,699		11,023
Investments and Other Assets				389		314
Assets of Discontinued Operations		(note 4)		1,486		1,450
			$	17,856	$	14,098
Liabilities and Shareholder’s Equity
Current Liabilities
	Accounts payable and accrued liabilities		$	1,458	$	980
	Income tax payable			—		242
	Current portion of long-term debt	(note 7)		100		25
				1,558		1,247
Long-Term Debt		(note 7)		4,926		3,658
Due to EnCana Corporation		(note 8)		366		—
Other Liabilities				232		204
Future Income Taxes				2,183		2,174
Non-Controlling Interest		(note 5)		638		—
Liabilities of Discontinued Operations		(note 4)		877		858
				10,780		8,141
Shareholder’s Equity
	Preferred securities			429		859
	Share capital	(note 9)		4,278		3,052
	Contributed surplus	(note 5)		178		—
	Retained earnings			1,923		1,788
	Foreign currency translation adjustment			268		258
				7,076		5,957
			$	17,856	$	14,098

See accompanying notes to Consolidated Financial Statements

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Consolidated Statement of Cash Flows

			September 30
			Three Months Ended						Nine Months Ended
(unaudited) ($ millions)			2002			2001			2002			2001
Operating Activities
	Net earnings from continuing operations		$	93		$	146		$	216		$	734
	Depreciation, depletion and amortization			333			289			1,047			856
	Future income taxes			207			(21	)		15			131
	Non-controlling interest — continuing operations			9			—			8			—
	Loss (gain) on sale of assets			—			(166	)		22			(166	)
	Cash tax on sale of Jonah Gas Gathering Company			—			52			—			52
	Other			86			124			(1	)		152
	Cash flow from continuing operations			728			424			1,307			1,759
	Cash flow from discontinued operations			14			13			54			44
	Cash flow			742			437			1,361			1,803
	Net change in non-cash working capital from continuing operations			(376	)		(84	)		(561	)		250
	Net change in non-cash working capital from discontinued operations			61			19			74			25
				427			372			874			2,078
Investing Activities
	Corporate acquisition	(note 5)		—			4			69			(431	)
	Capital expenditures			(1,180	)		(802	)		(3,046	)		(2,452	)
	Equity investments			(5	)		—			1			(27	)
	Proceeds on disposal of assets			119			612			387			728
	Net change in investments and other			(76	)		36			(62	)		24
	Cash tax on sale of Jonah Gas Gathering Company			—			(52	)		—			(52	)
	Net change in non-cash working capital from continuing operations			127			115			29			27
	Discontinued operations			3			(15	)		(18	)		(27	)
				(1,012	)		(102	)		(2,640	)		(2,210	)
Financing Activities
	Net issuance of long-term debt			(190	)		(157	)		901			523
	Issuance of intercorporate debt			(205	)		—			8			—
	Issuance of common shares	(note 9)		1,201			4			1,235			43
	Purchase of common shares			—			(121	)		(25	)		(208	)
	Dividends on common shares			—			—			(66	)		(90	)
	Payments to preferred securities holders			(11	)		(10	)		(27	)		(31	)
	Net change in non-cash working capital from continuing operations			(8	)		(7	)		(20	)		(24	)
	Discontinued operations			(4	)		(3	)		(11	)		(8	)
	Other			12			(25	)		(46	)		22
				795			(319	)		1,949			227
Increase (Decrease) in Cash and Cash Equivalents				210			(49	)		183			95
Cash and Cash Equivalents, Beginning of Period				29			156			56			12
Cash and Cash Equivalents, End of Period			$	239		$	107		$	239		$	107

See accompanying notes to Consolidated Financial Statements

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

1. Basis of Presentation

The interim consolidated financial statements include the accounts of Alberta Energy Company Ltd. and its subsidiaries (the “Company”), and are presented in accordance with Canadian generally accepted accounting principles. The Company is in the business of exploration, production and marketing of natural gas and crude oil, as well as pipelines, natural gas liquids processing and gas storage 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, 2001, except as described in Note 2. 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, 2001.

On January 27, 2002, the Company and PanCanadian Energy Corporation (“PanCanadian”) announced plans to combine their companies. The transaction, which closed on April 5, 2002, was accomplished through a plan of arrangement (the “Arrangement”) under the Business Corporations Act (Alberta). On April 5, 2002, PanCanadian changed its name to EnCana Corporation (“EnCana”). The Company is now an indirect wholly owned subsidiary of EnCana.

2. Changes in Accounting Policies

Foreign Currency Translation

Effective December 31, 2001 the Company adopted the new Canadian accounting standard for foreign currency translation and, as required by the standard, all prior periods have been restated. The net earnings impact of this change is included in foreign exchange and income taxes on the Consolidated Statement of Earnings.

3. Segmented Information

Due to the business combination as described in Note 1, the Company has redefined its operations into the following segments. Onshore North America includes the Company’s North America onshore exploration for, and production of, natural gas and crude oil. Offshore & International combines the Offshore & International Operations Division’s exploration for, and production of, crude oil and natural gas in Ecuador and the Gulf of Mexico with the Offshore & New Ventures Exploration Division’s exploration activity in the North American frontier region, the Gulf of Mexico, the Middle East and Latin America. Midstream & Marketing includes natural gas liquids processing and gas storage operations, as well as, marketing activity under which the Company purchases and takes delivery of product from others and delivers product to customers under transportation arrangements not utilized for the Company’s own production. All prior periods have been restated to conform to these definitions. Operations that have been discontinued are disclosed in Note 4.

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

3. Segmented Information (continued)

($ millions)
RESULTS OF OPERATIONS (FOR THE THREE MONTHS ENDED)

		Onshore North America				Offshore & International				Midstream & Marketing
		2002		2001		2002		2001		2002		2001
Revenues
	Gross revenue	$	937	$	717	$	186	$	150	$	861	$	615
	Royalties and production taxes		138		137		64		46		—		—
	Revenues, net of royalties and production taxes		799		580		122		104		861		615
Expenses
	Transportation and selling		70		43		14		15		43		37
	Operating		150		141		32		34		39		24
	Purchased product		—		—		—		—		755		540
	Depreciation, depletion and amortization		283		233		41		46		6		7
	(Gain) on sale of assets		—		—		—		—		—		(166	)
	Segment income	$	296	$	163	$	35	$	9	$	18	$	173

		Corporate						Consolidated
		2002			2001			2002		2001
Revenues
	Gross revenue	$	—		$	—		$	1,984	$	1,482
	Royalties and production taxes		—			—			202		183
	Revenues, net of royalties and production taxes		—			—			1,782		1,299
Expenses
	Transportation and selling		—			—			127		95
	Operating		—			—			221		199
	Purchased product		—			—			755		540
	Depreciation, depletion and amortization		3			3			333		289
	(Gain) on sale of assets		—			—			—		(166	)
	Segment income		(3	)		(3	)		346		342
	Administrative		31			20			31		20
	Interest, net		87			57			87		57
	Foreign exchange		71			79			71		79
Net Earnings Before Income Tax			(192	)		(159	)		157		186
	Income tax expense		55			40			55		40
	Non-controlling interest								9		—
Net Earnings from Continuing Operations		$	(247	)	$	(199	)	$	93	$	146

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

3. Segmented Information (continued)

GEOGRAPHIC AND PRODUCT INFORMATION (FOR THE THREE MONTHS ENDED)

Onshore North America		Produced Gas & NGL’s
		Canada				U.S. Rockies
		2002		2001		2002		2001
Revenues
	Gross revenue	$	377	$	402	$	246	$	93
	Royalties and production taxes		59		83		55		25
	Revenues, net of royalties and production taxes		318		319		191		68
Expenses
	Transportation and selling		28		31		32		5
	Operating		58		58		18		5
Operating Cash Flow		$	232	$	230	$	141	$	58

		Conventional								Total Onshore
		Crude Oil				Syncrude				North America
		2002		2001		2002		2001		2002		2001
Revenues
	Gross revenue	$	171	$	112	$	143	$	110	$	937	$	717
	Royalties and production taxes		22		15		2		14		138		137
	Revenues, net of royalties and production taxes		149		97		141		96		799		580
Expenses
	Transportation and selling		8		6		2		1		70		43
	Operating		30		23		44		55		150		141
Operating Cash Flow		$	111	$	68	$	95	$	40	$	579	$	396

Offshore & International												Total Offshore
		Ecuador				Other International						& International
		2002		2001		2002			2001			2002		2001
Revenues
	Gross revenue	$	186	$	150	$	—		$	—		$	186	$	150
	Royalties and production taxes		64		46		—			—			64		46
	Revenues, net of royalties and production taxes		122		104		—			—			122		104
Expenses
	Transportation and selling		14		15		—			—			14		15
	Operating		24		24		8			10			32		34
Operating Cash Flow		$	84	$	65	$	(8	)	$	(10	)	$	76	$	55

Midstream & Marketing											Total Midstream
		Midstream				Marketing					& Marketing
		2002		2001		2002		2001			2002		2001
Revenues
	Gross revenue	$	132	$	108	$	729	$	507		$	861	$	615
Expenses
	Transportation and selling		—		—		43		37			43		37
	Operating		37		24		2		—			39		24
	Purchased product		72		41		683		499			755		540
Operating Cash Flow		$	23	$	43	$	1	$	(29	)	$	24	$	14

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

3. Segmented Information (continued)

($ millions)
RESULTS OF OPERATIONS (FOR THE NINE MONTHS ENDED)

		Onshore North America				Offshore & International						Midstream & Marketing
		2002		2001		2002			2001			2002		2001
Revenues
	Gross revenue	$	2,510	$	2,968	$	457		$	434		$	1,914	$	2,279
	Royalties and production taxes		395		606		147			126			—		—
	Revenues, net of royalties and production taxes		2,115		2,362		310			308			1,914		2,279
Expenses
	Transportation and selling		169		114		36			46			129		112
	Operating		467		411		105			107			89		107
	Purchased product		—		—		—			—			1,610		1,933
	Depreciation, depletion and amortization		792		644		198			179			46		24
	Loss (gain) on sale of assets		—		—		17			—			5		(166	)
	Segment income (loss)	$	687	$	1,193	$	(46	)	$	(24	)	$	35	$	269

		Corporate						Consolidated
		2002			2001			2002			2001
Revenues
	Gross revenue	$	—		$	—		$	4,881		$	5,681
	Royalties and production taxes		—			—			542			732
	Revenues, net of royalties and production taxes		—			—			4,339			4,949
Expenses
	Transportation and selling		—			—			334			272
	Operating		—			—			661			625
	Purchased product		—			—			1,610			1,933
	Depreciation, depletion and amortization		11			9			1,047			856
	Loss (gain) on sale of assets		—			—			22			(166	)
	Segment income		(11	)		(9	)		665			1,429
	Administrative		75			53			75			53
	Interest, net		229			154			229			154
	Foreign exchange		(15	)		98			(15	)		98
Net Earnings Before Income Tax			(300	)		(314	)		376			1,124
	Income tax expense		152			390			152			390
	Non-controlling interest								8			—
Net Earnings from Continuing Operations		$	(452	)	$	(704	)	$	216		$	734

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

3.     Segmented Information (continued)

GEOGRAPHIC AND PRODUCT INFORMATION (FOR THE NINE MONTHS ENDED)

Onshore North America		Produced Gas & NGL’s
		Canada				U.S. Rockies
		2002		2001		2002		2001
Revenues
	Gross revenue	$	1,246	$	1,941	$	499	$	390
	Royalties and production taxes		228		426		117		106
	Revenues, net of royalties and production taxes		1,018		1,515		382		284
Expenses
	Transportation and selling		93		81		52		13
	Operating		191		160		36		16
Operating Cash Flow		$	734	$	1,274	$	294	$	255

		Conventional Crude Oil				Syncrude				Nort America
		2002		2001		2002		2001		2002		2001
Revenues
	Gross revenue	$	431	$	279	$	334	$	358	$	2,510	$	2,968
	Royalties and production taxes		48		37		2		37		395		606
	Revenues, net of royalties and production taxes		383		242		332		321		2,115		2,362
Expenses
	Transportation and selling		20		15		4		5		169		114
	Operating		78		63		162		172		467		411
Operating Cash Flow		$	285	$	164	$	166	$	144	$	1,479	$	1,837

Offshore & International												Total Offshore
		Ecuador				Other International						& International
		2002		2001		2002			2001			2002		2001
Revenues
	Gross revenue	$	457	$	432	$	—		$	2		$	457	$	434
	Royalties and production taxes		147		126		—			—			147		126
	Revenues, net of royalties and production taxes		310		306		—			2			310		308
Expenses
	Transportation and selling		36		46		—			—			36		46
	Operating		75		72		30			35			105		107
Operating Cash Flow		$	199	$	188	$	(30	)	$	(33	)	$	169	$	155

											Total Midstream
Midstream & Marketing		Midstream				Marketing					& Marketing
		2002		2001		2002		2001			2002		2001
Revenues
	Gross revenue	$	363	$	591	$	1,551	$	1,688		$	1,914	$	2,279
Expenses
	Transportation and selling		—		—		129		112			129		112
	Operating		87		94		2		13			89		107
	Purchased product		212		339		1,398		1,594			1,610		1,933
Operating Cash Flow		$	64	$	158	$	22	$	(31	)	$	86	$	127

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

3. Segmented Information (continued)

CAPITAL EXPENDITURES

	September 30
	Three months ended				Nine months ended
	2002		2001		2002		2001
Onshore North America	$	963	$	538	$	2,387	$	1,781
Offshore & International		181		174		489		435
Midstream & Marketing		17		85		138		213
Corporate		19		5		32		23
	$	1,180	$	802	$	3,046	$	2,452

CAPITAL AND TOTAL ASSETS

	As at
	Capital Assets				Total Assets
	September 30,		December 31,		September 30,		December 31,
	2002		2001		2002		2001
Onshore North America	$	10,443	$	8,632	$	11,270	$	9,250
Offshore & International		2,521		1,904		2,775		2,023
Midstream & Marketing		676		439		1,605		1,226
Corporate		59		48		720		149
Assets from Discontinued Operations		—		—		1,486		1,450
	$	13,699	$	11,023	$	17,856	$	14,098

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

4. Discontinued Operations

Merchant Energy

On May 31, 2002, the Company acquired the Houston-based merchant energy operation from its parent company, EnCana Corporation, in exchange for common shares, as described in Note 5. A formal plan to dispose of these operations was adopted on April 24, 2002. Accordingly, the Company accounts for these operations as discontinued operations.

Pipelines

On July 9, 2002, the Company announced that it plans to sell its 70% interest in the Cold Lake Pipeline System and its 100% interest in the Express Pipeline System, both crude oil pipeline systems. Accordingly, these investments have been accounted for as discontinued operations.

Both of these discontinued operations were included in the Midstream and Marketing segment.

		For the three months ended September 30
Consolidated Statement of Earnings ($ millions)		Merchant Energy					Pipelines				Total
		2002			2001		2002		2001		2002			2001
Gross Revenues		$	154		$	—	$	91	$	58	$	245		$	58
Expenses
	Operating		—			—		33		22		33			22
	Purchased product		162			—		—		—		162			—
	Administrative		16			—		—		—		16			—
	Interest, net		—			—		11		11		11			11
	Foreign exchange		—			—		7		8		7			8
	Depreciation, depletion and amortization		—			—		12		14		12			14
	(Gain) on discontinuance		(29	)		—		—		—		(29	)		—
			149			—		63		55		212			55
Net Earnings Before Income Tax			5			—		28		3		33			3
	Income tax expense		2			—		11		3		13			3
Net Earnings from Discontinued Operations		$	3		$	—	$	17	$	—	$	20		$	—

		For the nine months ended September 30
		Merchant Energy *					Pipelines					Total
		2002			2001		2002			2001		2002			2001
Gross Revenues		$	316		$	—	$	197		$	168	$	513		$	168
Expenses
	Operating		—			—		67			65		67			65
	Purchased product		327			—		—			—		327			—
	Administrative		17			—		—			—		17			—
	Interest, net		—			—		33			34		33			34
	Foreign exchange		—			—		(2	)		10		(2	)		10
	Depreciation, depletion and amortization		—			—		36			37		36			37
	(Gain) on discontinuance		(16	)		—		—			—		(16	)		—
			328			—		134			146		462			146
Net (Loss) Earnings Before Income Tax			(12	)		—		63			22		51			22
	Income tax expense		(3	)		—		25			12		22			12
Net (Loss) Earnings from Discontinued Operations		$	(9	)	$	—	$	38		$	10	$	29		$	10

* includes results from May 31, 2002, the date the operations were acquired.

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

4. Discontinued Operations (continued)

		As at September 30
Consolidated Balance Sheet ($ millions)		Merchant Energy				Pipelines					Total
		2002		2001		2002		2001			2002		2001
Assets
	Cash and cash equivalents	$	—	$	—	$	60	$	48		$	60	$	48
	Accounts receivable and accrued revenue		55		—		32		37			87		37
	Inventories		—		—		1		1			1		1
			55		—		93		86			148		86
	Capital assets, net		—		—		819		1,245			819		1,245
	Investments and other assets		—		—		519		43			519		43
			55		—		1,431		1,374			1,486		1,374
Liabilities
	Accounts payable and accrued liabilities		30		—		44		83			74		83
	Income tax payable		—		—		5		(1	)		5		(1	)
	Current portion of long-term debt		—		—		25		22			25		22
			30		—		74		104			104		104
	Long-term debt		—		—		562		587			562		587
	Future income taxes		—		—		211		119			211		119
			30		—		847		810			877		810
Net Assets of Discontinued Operations		$	25	$	—	$	584	$	564		$	609	$	564

For comparative purposes, the following tables show the results of Discontinued Operations on the Consolidated Financial Statements for the years ended December 31.

		Year ended December 31
Consolidated Statement of Earnings ($ millions)		Pipelines
		2001		2000
Gross Revenues		$	227	$	144
Expenses
	Operating		85		49
	Interest, net		46		24
	Foreign exchange		10		8
	Depreciation, depletion and amortization		50		33
			191		114
Net Earnings Before Income Taxes			36		30
	Income tax expense		24		19
Net Earnings from Discontinued Operations		$	12	$	11

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

4. Discontinued Operations (continued)

		As at December 31
Consolidated Balance Sheet ($ millions)		Pipelines
		2001		2000
Assets
	Cash and cash equivalents	$	48	$	33
	Accounts receivable and accrued revenue		49		46
	Inventories		1		—
			98		79
	Capital assets, net		844		1,230
	Investments and other assets		508		36
			1,450		1,345
Liabilities
	Accounts payable and accrued liabilities		63		65
	Income tax payable		—		(3	)
	Current portion of long-term debt		24		16
			87		78
	Long-term debt		584		573
	Future income taxes		187		144
			858		795
Net Assets of Discontinued Operations		$	592	$	550

At September 30, 2002 and December 31, 2001, the Company’s interest in the Cold Lake Pipeline System is held through its equity investment in the Cold Lake Pipeline Limited Partnership, which commenced operations on December 21, 2001. The Company earned its interest in the Cold Lake Pipeline Limited Partnership by contributing its existing interest in the original Cold Lake Pipeline System as well as contributing cash for its share of a new expansion pipeline between Cold Lake and Hardisty, Alberta and a pipeline lateral connecting producing areas with the Cold Lake Pipeline System. Prior to December 31, 2001, the Company owned the original Cold Lake Pipeline System through an indirect wholly owned subsidiary.

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

5. Related Party Transaction

On May 31, 2002, the Company, through its wholly owned subsidiary Alenco Inc., acquired, from its parent company, EnCana Corporation (“EnCana”), all of the common shares of EnCana Energy Holdings Inc. (“Holdings”) and EnCana GOM Inc. (“GOM”) in exchange for common shares representing approximately 33% ownership of Alenco Inc. Holdings and GOM collectively represented the upstream and midstream business carried on by EnCana in the United States. The acquisition of Holdings includes the Houston-based merchant energy operation which has been accounted for as discontinued operations, based on EnCana’s adoption of formal plans to dispose of the operations on April 24, 2002.

The acquisition was accounted for using the historical book values recorded by EnCana. Upon completion of the transaction, the Company’s share of the post acquisition shareholders’ equity of Alenco Inc. increased and was recorded as Contributed Surplus.

6. Income Taxes

The provision for income taxes is as follows:

		September 30
		Three months ended						Nine months ended
($ millions)		2002			2001			2002			2001
Current
	Canada	$	(103	)	$	4		$	169		$	177
	United States		(57	)		51			(48	)		54
	Ecuador		7			6			15			27
	Other		1			—			1			1
			(152	)		61			137			259
Future			207			(21	)		15			131
		$	55		$	40		$	152		$	390

7. Long-Term Debt

		As at		As at
		September 30		December 31
($ millions)		2002		2001
Canadian dollar debt
	Revolving credit and term loan borrowings	$	1,100	$	350
	Unsecured debentures, including Capital Securities		1,830		1,425
			2,930		1,775
U.S. dollar debt
	U.S. unsecured senior notes		1,900		1,908
	U.S. revolving credit and term loan borrowings		196		—
			5,026		3,683
Current portion of long-term debt			100		25
		$	4,926	$	3,658

On October 16, 2002, the Company announced that it had established October 22, 2002 as the record date for a meeting of holders of its Capital Securities to consider, and if thought advisable, to approve, amendments to the terms of such Capital Securities to provide the Company with the right to call for the early redemption of the Capital Securities with a face value of $430 million.

Interim Report Alberta Energy Company Ltd.

For the period ended September 30, 2002

Notes to Consolidated Financial Statements (unaudited)

8. Due to EnCana Corporation

Included in the amount Due to EnCana Corporation of $366 million is a US$238 million promissory note, which bears interest at 7.5%. The remaining balances are non-interest bearing and also unsecured.

9. Share Capital

During the three months ended September 30, 2002, the Company issued common shares to its parent company for cash consideration of $1,201 million.

10. Reclassification

Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2002.

ALBERTA ENERGY COMPANY LTD.

(a wholly owned subsidiary of EnCana Corporation)

Management’s Discussion and Analysis

For the period ended September 30, 2002

1

SPECIAL NOTE REGARDING FORWARD-LOOKING INFORMATION

         In the interest of providing Alberta Energy Company Ltd. (“AEC” or the “Company”) shareholders and potential investors with information regarding the Company, certain statements throughout this Interim Management’s Discussion and Analysis (“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” 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: oil and gas prices; the Company’s oil, liquids and gas sales; the Company’s cash flow and net earnings; the Company’s production levels; the impact of hedges on the Company’s revenue; capital investment levels; the sources of funding for capital investments; the volatility of world energy prices; the anticipated timing and results of discontinuing the Houston-based merchant energy operation and the proposed disposition of the Express and Cold Lake pipeline interests; the redeployment of proceeds from the disposition of such pipeline interests; the impact of the Company’s risk management program; completion of the OCP pipeline; transportation capacity of the OCP pipeline and the Company’s ability to utilize transportation capacity.

         Readers are cautioned not to place undue reliance on forward-looking information, as there can be no assurance that the plans, intentions or expectations upon which it is based will occur. By its nature, forward-looking information involves 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. Although the Company 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. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A include, but are not limited to: volatility of crude oil and natural gas prices, fluctuations in currency and interest rates, product supply and demand, market competition, risks inherent in the Company’s North American and foreign oil and gas and midstream operations, risks inherent in the Company’s marketing operations, imprecision of reserves estimates, the Company’s ability to replace and expand oil and gas reserves, the Company’s ability to either generate sufficient cash flow from operations to meet its current and future obligations or obtain external sources of debt and equity capital, general economic and business conditions, the Company’s ability to enter into or renew leases, the timing and costs of well and pipeline construction, the Company’s ability to make capital investments and the amounts of capital investments, imprecision in estimating the timing, costs and levels of production and drilling, the results of exploration and development drilling, imprecision in estimates of future production capacity, the Company’s ability to secure adequate product transportation, uncertainty in the amounts and timing of royalty payments, imprecision in estimates of product sales, changes in environmental and other regulations, political and economic conditions in the countries in which the Company operates including Ecuador, and such other risks and uncertainties described from time to time in the Company’s reports and filings with the Canadian securities authorities and the United States Securities and Exchange Commission. Accordingly, the Company cautions that events or circumstances could cause actual results to differ materially from those predicted. Statements relating to “reserves” or “resources” 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 can be profitably produced in the future. Readers are cautioned that the foregoing list of important factors is not exhaustive. Readers are further cautioned not to place undue reliance on forward-looking statements contained in this MD&A, which is as of the date hereof, and the Company undertakes no obligation to update publicly or revise any forward-looking information, 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.

2

This Interim Management’s Discussion and Analysis (“MD&A”) for Alberta Energy Company Ltd. (“AEC”) should be read in conjunction with the unaudited interim consolidated financial statements for the nine months ended September 30, 2002 and September 30, 2001 and the audited consolidated financial statements and MD&A for the year ended December 31, 2001.

CONSOLIDATED OVERVIEW

On April 5, 2002, AEC and PanCanadian Energy Corporation (“PanCanadian”) completed the merger of their two companies, creating EnCana Corporation (“EnCana”). The companies satisfied all closing conditions, including receipt of approvals from shareholders of PanCanadian, shareholders and optionholders of AEC, and the Court of Queen’s Bench of Alberta. Under the terms of the merger, AEC shareholders received 1.472 EnCana common shares for each AEC common share owned. AEC is now an indirect wholly owned subsidiary of EnCana.

On May 31, 2002, one of AEC’s subsidiaries acquired certain related companies, through an exchange of shares, from its ultimate parent company, EnCana, as described in Note 5 to the unaudited interim consolidated financial statements (“Consolidated Financial Statements”). The companies acquired collectively represented the upstream and midstream business carried on by EnCana in the United States. As a result of this transaction, a non-controlling interest of $9 million has been reflected in the Company’s third quarter net earnings from continuing operations, $8 million in the year to date, representing EnCana’s non-controlling ownership in one of the Company’s subsidiaries. Included in the acquired U.S. operations is a Houston-based merchant energy operation that was substantially wound-down in the third quarter of 2002. Consequently, year-to-date results included an after-tax loss of $9 million, the results of the discontinued operations from the date of acquisition.

AEC’s 2002 third quarter net earnings from continuing operations were $93 million compared with $146 million in the third quarter of 2001. The 2001 third quarter results included a $166 million gain on the sale of the Jonah Gas Gathering System. Third quarter earnings in 2002 were also impacted by an after-tax foreign exchange loss of $69 million related to the translation of U.S. dollar denominated long-term debt. The third quarter foreign exchange loss compared to an after-tax foreign exchange gain of $79 million recorded in the second quarter. The year-to-date impact of the translation of U.S. dollar denominated long-term debt was an after-tax gain of $8 million. Quarterly cash flow from continuing operations was $728 million, an increase of $304 million over the third quarter of last year. Increased production of natural gas and crude oil in combination with higher crude oil prices largely offset the effect of weaker Western Canada and U.S. Rockies regional (“regional”) natural gas prices in the quarter.

For the nine months ended September 30, 2002, net earnings from continuing operations of $216 million were down from $734 million in the same period of 2001. Cash flow from continuing operations was $1,307 million, a decline of $452 million from the corresponding period last year. The lower 2002 results primarily reflect the impact of weaker regional market prices for natural gas, which were only partially offset by increased natural gas and crude oil production levels.

	Three months ended				Nine months ended
	September 30				September 30
Consolidated Financial Summary ($ millions)	2002		2001		2002		2001
Revenues, net of royalties and production taxes	$	1,782	$	1,299	$	4,339	$	4,949
Net earnings from continuing operations		93		146		216		734
Net earnings		108		146		243		744
Cash flow from continuing operations		728		424		1,307		1,759
Cash flow		742		437		1,361		1,803

3

On August 1, 2002, the Company announced that one of its U.S. subsidiaries had further strengthened its position in the U.S. Rocky Mountain region through the purchase of producing and non-producing assets in the Jonah field, in southwest Wyoming, for approximately $539 million. The acquisition included developed and undeveloped reserves and increased the Company’s interest in the Jonah field production from approximately 50 percent to approximately 75 percent.

On July 9, 2002, the Company announced plans to dispose of its interests in two major crude oil pipeline systems. The proposed disposition includes the Company’s indirect 100 percent interest in the Express Pipeline System and its indirect 70 percent interest in the Cold Lake Pipeline System. During the third quarter, progress was made in regards to the planned disposition and the Company expects to complete a sale later in the fourth quarter. It is anticipated that, upon the proposed disposition, the proceeds will initially be used to reduce debt prior to being re- deployed into other strategic initiatives.

The merchant energy and pipeline operations described above have both been accounted for as discontinued operations as described in Note 4 to the Consolidated Financial Statements.

BUSINESS ENVIRONMENT

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2002		2001		2002		2001
Average AECO Price ($ per thousand cubic feet)		3.25		3.92		3.67		7.30
Average NYMEX Price (US$ per million British thermal units)		3.26		2.98		3.01		5.01
WTI Average (US$ per barrel)		28.25		26.60		25.45		27.77
WTI-Bow River Differential (US$ per barrel)		5.38		7.16		5.35		9.99
Oriente Differential (Ecuador) (US$ per barrel)		4.35		5.22		4.28		7.35
U.S./Canadian dollar exchange rate (US$)		0.640		0.647		0.637		0.650

High levels of natural gas in storage, resulting from decreased demand, continued to have a negative impact on natural gas prices. In the third quarter, the AECO index price per thousand cubic feet averaged $3.25 compared with $3.92 in the same quarter of 2001. The average AECO index price for the nine months ended September 30, 2002 of $3.67 per thousand cubic feet was down approximately 50 percent in comparison to the same period last year. The NYMEX to AECO basis differential has widened through the year as it averaged US$0.29 per million British thermal units in the first quarter of 2002 compared with US$1.17 per million British thermal units in the third quarter, as a result of pipeline maintenance programs, less demand in the U.S. Pacific Northwest due to higher hydro electric generation and high levels of gas in storage in the western U.S.

World crude oil prices maintained their upward trend during the third quarter of 2002. The benchmark West Texas Intermediate (“WTI”) crude oil price averaged US$28.25 per barrel in the third quarter, up six percent from the same quarter last year. The increase in the quarter largely reflected a “war premium” resulting from worries over escalating conflicts with Iraq. For the year to date, the average WTI crude oil price was US$25.45 per barrel, a decrease of eight percent from the same period of 2001, reflecting the negative impact of low first quarter prices.

The differential between heavy and light crude oil prices continued to benefit from improvements in the supply/demand balance for heavy oil. The WTI-Bow River differential averaged US$5.38 per barrel in the third quarter and US$5.35 per barrel in the nine months, a narrowing of 25 percent and 46 percent from the respective periods of 2001.

4

RESULTS OF OPERATIONS

Upstream – Onshore North America and Offshore & International

		Three months ended September 30
		2002								2001
		Produced		Conventional						Produced		Conventional
Financial Results ($ millions)		Gas & NGL's		Crude Oil		Syncrude		Total		Gas & NGL's		Crude Oil		Syncrude		Total
Revenues
	Gross revenue	$	623	$	357	$	143	$	1,123	$	495	$	262	$	110	$	867
	Royalties and production taxes		114		86		2		202		108		61		14		183
Revenues, net of royalties and production taxes			509		271		141		921		387		201		96		684
Expenses
	Transportation and selling		60		22		2		84		36		21		1		58
	Operating		76		62		44		182		63		57		55		175
	Depreciation, depletion and amortization								324								279
Upstream income		$	373	$	187	$	95	$	331	$	288	$	123	$	40	$	172
Capital expenditures (excludes dispositions)								$	1,144							$	712

		Nine months ended September 30
		2002								2001
		Produced		Conventional						Produced		Conventional
Financial Results ($ millions)		Gas & NGL's		Crude Oil		Syncrude		Total		Gas & NGL's		Crude Oil		Syncrude		Total
Revenues
	Gross revenue	$	1,745	$	888	$	334	$	2,967	$	2,331	$	713	$	358	$	3,402
	Royalties and production taxes		345		195		2		542		532		163		37		732
Revenues, net of royalties and production taxes			1,400		693		332		2,425		1,799		550		321		2,670
Expenses
	Transportation and selling		145		56		4		205		94		61		5		160
	Operating		227		183		162		572		176		170		172		518
	Depreciation, depletion and amortization								990								823
	Loss on sale of assets								17
Upstream income		$	1,028	$	454	$	166	$	641	$	1,529	$	319	$	144	$	1,169
Capital expenditures (excludes dispositions)								$	2,876							$	2,216

5

	Three months ended September 30						Nine months ended September 30
Revenue Variances for 2002
Compared to 2001 ($ millions)	Price		Volume		Total		Price			Volume		Total
Produced gas and NGL’s	$	39	$	89	$	128	$	(1,152	)	$	566	$	(586	)
Conventional crude oil		47		48		95		94			81		175
Syncrude		6		27		33		(30	)		6		(24	)
Total gross revenue	$	92	$	164	$	256	$	(1,088	)	$	653	$	(435	)

Revenues

The Company reports its segmented financial results showing revenue prior to all royalty payments, both cash and in-kind, consistent with Canadian disclosure practices for the oil and gas industry. Third quarter gross revenue rose 30 percent, or $256 million, to $1,123 million compared with the same quarter in 2001. Gross revenue for the year to date were $2,967 million, a 13 percent decline from the same period last year.

Produced Gas and NGL’s

Sales of produced gas and natural gas liquids contributed $623 million to revenues in the third quarter of 2002, an increase of $128 million over the same quarter of 2001. Produced gas sales volumes in the quarter were 1,643 million cubic feet per day, an 18 percent improvement over the same period of 2001. Growth in sales was driven mainly by drill bit success in the U.S. Rockies and northeast British Columbia and the property acquisitions in the U.S. Rockies. For the three months ended September 30, 2002, realized natural gas prices averaged $3.53 per thousand cubic feet, up from $3.17 per thousand cubic feet in the same period of 2001. Natural gas revenues in the quarter were $50 million higher as the result of a gain from commodity hedging activities. This compared with a loss of approximately $1 million in the third quarter of last year.

Produced gas and natural gas liquids revenues for the year to date were $1,745 million, a 25 percent decrease from the same period in 2001. The decline largely reflects the decrease in realized natural gas prices, which at $3.54 per thousand cubic feet, were down 42 percent from the corresponding period of last year. During the first nine months of 2002, natural gas sales volumes averaged 1,597 million cubic feet per day compared with 1,286 million cubic feet per day in the same period of 2001. Hedging activities in the first nine months of 2002 increased natural gas revenues by $30 million, this compares with a reduction of approximately $1 million for the same period of 2001.

Conventional Crude Oil

Third quarter revenues from the sale of conventional crude oil were $357 million, an improvement of $95 million, or 36 percent, over the same quarter in 2001. The increase in revenues is primarily the result of additional sales volumes from the Foster Creek Steam-Assisted Gravity Drainage (“SAGD”) project and Suffield in combination with higher world oil prices. Commodity hedging in the quarter resulted in a $5 million loss compared with a gain of $1 million in the same quarter of 2001.

Onshore North America conventional crude oil sales volumes averaged 62,458 barrels per day during the third quarter compared with 48,432 barrels per day in the same quarter of 2001. Higher volume levels are primarily attributable to the Foster Creek SAGD project, which commenced commercial production late in 2001, and increased production at Suffield. The Company’s realized price from Onshore North America crude averaged $28.42 per barrel in the quarter, an improvement over an average price of $25.83 per barrel in the same period last year.

Third quarter sales volumes from Offshore and International, in Ecuador, were 55,579 barrels per day, which compares with 51,472 barrels per day in the third quarter of 2001. Realized crude oil prices from the Company’s

6

Ecuador crude averaged $33.59 per barrel compared with a realized price of $28.43 per barrel in the third quarter of last year.

Revenues from conventional crude oil for the year to date increased by 25 percent to $888 million compared with the same period last year. The improvement in gross revenues was attributable to the higher volumes resulting from commercial development of the Foster Creek SAGD project and increased production from Suffield in combination with the strengthened world oil prices and the decrease in light-heavy oil differentials. Year-to-date realized crude oil prices from Onshore North America averaged $26.24 per barrel compared with $21.78 per barrel in the corresponding period of 2001. Hedging activities for the nine months ended September 2002 resulted in a hedging loss of $4 million, in comparison with a hedging gain of $1 million for the same period of 2001. Offshore and International conventional crude oil activities had an average realized price of $29.97 per barrel in Ecuador compared with an average of $27.11 per barrel for the same period last year.

Syncrude

Third quarter revenues from Syncrude were up $33 million compared with the same quarter in 2001. In the three months ended September 2002, Syncrude sales averaged 36,039 barrels per day at an average realized price of $42.54 per barrel compared with 28,938 barrels per day at an average realized price of $40.74 per barrel for the corresponding period of 2001. Production was higher in the third quarter of 2002 as there was no major maintenance and all units were operating at maximum production rates compared with the same quarter of 2001.

For the year to date, Syncrude revenues amounted to $334 million, a decline of seven percent from the $358 million reported in the first nine months of last year. The drop in revenues reflects lower realized prices, $39.28 per barrel for the year to date compared with $42.09 in the corresponding period of 2001. Syncrude sales averaged 30,644 barrels per day in the first nine months of 2002, a slight increase over 30,127 barrels per day for the same period of 2001.

Royalties and Production Taxes

Royalties and production taxes were 19 percent of revenues, excluding the impact of hedging, in the third quarter of 2002 compared with 21 percent in the same quarter of last year. For the nine months ended September 30, 2002, this rate was 18 percent, which compares with 22 percent for the same period of 2001. The decreased rates reflect the impact of lower energy prices partially offset by increases in production.

Expenses

Transportation and selling costs were $84 million in the third quarter compared with $58 million in the third quarter of 2001. For the nine months ending September 30, 2002, these costs amounted to $205 million compared with $160 million in the corresponding period last year. Higher sales volumes in the quarter and the year to date are the principal factor contributing to the increase in these costs. For the purpose of the revenue variance discussion above, these costs have been netted against revenues in calculating the per unit realized prices for each commodity.

7

	Three months ended				Nine months ended
	September 30				September 30
Unit Operating Expenses* ($ per unit)	2002		2001		2002		2001
Produced gas (per thousand cubic feet)	$	0.50	$	0.49	$	0.52	$	0.50
Conventional crude oil (per barrel)		4.97		5.11		5.15		5.04
Per barrel of oil equivalent**		3.50		3.52		3.61		3.57
Syncrude (per barrel)		13.38		20.75		19.37		20.89

• excluding operating costs from Other International, as described in Note 3 to the Consolidated Financial Statements, and cost recoveries

• natural gas converted to barrel of oil equivalent at 6 thousand cubic feet = 1 barrel of oil equivalent

Conventional oil and gas operating expenses were $138 million in the quarter, an increase of $18 million over the same quarter of 2001. For the year to date, these costs were $410 million, up from $346 million in the corresponding period of last year. The higher expenses were mainly attributable to the growth in sales volumes relative to the third quarter of 2001. On a per unit basis, operating expenses in the quarter were $3.50 per barrel of oil equivalent, essentially unchanged from $3.52 per barrel of oil equivalent in the third quarter of 2001. For the year to date, these expenses were $3.61 per barrel of oil equivalent, a slight increase over $3.57 per barrel of oil equivalent in the first nine months of last year.

For produced gas, unit operating costs were $0.50 per thousand cubic feet in the quarter compared with $0.49 per thousand cubic feet in 2001 and $0.52 per thousand cubic feet for the year to date, up slightly from $0.50 per thousand cubic feet in the first nine months of last year.

Unit operating costs for crude oil were down to $4.97 per barrel in the third quarter from $5.11 per barrel in the same quarter of 2001. This improvement in operating costs reflected the impact of lower electricity costs and increased production from lower operating cost properties in the third quarter of 2002. For the year to date, operating costs were $5.15 per barrel compared with $5.04 per barrel for the same period last year.

For Syncrude, unit operating costs were $13.38 per barrel in the third quarter of 2002, a 36 percent decrease from costs of $20.75 per barrel in the same quarter last year. Year-to-date unit operating costs for Syncrude were $19.37, which compares to $20.89 for the first nine months of 2001. Year-to-date operating costs have decreased as a result of lower fuel gas costs combined with reduced mining and contract labour expenses.

Depreciation, depletion and amortization charges amounted to $324 million in the quarter and $990 million for the year to date compared with charges of $279 million and $823 million in the respective periods last year. These increases mainly reflect the impact of higher produced gas and crude oil volumes relative to the same periods in 2001.

Compared with last year, upstream capital expenditures, excluding dispositions, increased $432 million in the third quarter and $660 million in the year to date. The majority of the capital expenditures were directed towards exploration and development in the Onshore North America division through its expansion in the U.S. Rocky Mountain region, combined with further exploration and development of the Greater Sierra area of northeastern British Columbia and the Suffield area in southeastern Alberta.

8

Midstream & Marketing

		Three months ended					Nine months ended
		September 30					September 30
Financial Results* ($ millions)		2002		2001			2002		2001
Revenues		$	861	$	615		$	1,914	$	2,279
Expenses
	Transportation and selling		43		37			129		112
	Operating		39		24			89		107
	Purchased product		755		540			1,610		1,933
	Depreciation and amortization		6		7			46		24
	Loss (gain) on sale of assets		—		(166	)		5		(166	)
		$	18	$	173		$	35	$	269
Capital expenditures (excludes dispositions)		$	17	$	85		$	138	$	213

• Results o f the Midstream & Marketing segment exclude financial results related to discontinued operations as described in Note 4 to the Consolidated Financial Statements.

In the three months ended September 30, 2002, revenues from continuing midstream operations were $132 million, an increase of $24 million over the same period last year. The increase in the quarter primarily reflected the addition of the results of the midstream business acquired by the Company in May 2002, as described in Note 5 to the Consolidated Financial Statements. In the year to date, these revenues were $363 million, a decline of $228 million over the first nine months of 2001. The decline was primarily the result of decreased storage optimization.

The Company’s purchased gas activity in the third quarter resulted in a margin from continuing operations of $1 million, a $30 million improvement over the same quarter in 2001. During the third quarter of 2001, the Company elected to close gas purchase agreements in place for future deliveries and, as a result, recorded additional costs of purchased product of approximately $30 million. In the year to date, Marketing activity from continuing operations resulted in a margin of $22 million, an increase of $53 million from the prior year.

Capital expenditures from continuing operations in the midstream division were $17 million in the quarter down from $85 million in the same quarter of 2001. For the year to date, capital expenditures amounted to $138 million compared with $213 million in the first nine months of last year. The 2002 expenditures related primarily to ongoing improvements to midstream facilities. Expenditures in 2001 included the Transandino pipeline and Salt Plains gas storage acquisitions.

The construction of the 450,000 barrel per day OCP pipeline in Ecuador is continuing on target for completion in the third quarter of 2003. It is expected that restricted transportation service at approximately 220,000 barrels per day will be available by the middle of 2003. To date, $27 million has been invested related to the Company’s 31.4% equity interest in the pipeline project.

9

Corporate

In the third quarter of 2002, foreign exchange resulted in a $71 million loss compared to a $79 million loss in the same quarter of 2001. For the year to date, the total impact from foreign exchange was a gain of $15 million, which compared to a $98 million loss in the first nine months of last year. The majority of the foreign exchange impact results from the translation of U.S. dollar denominated debt where exchange gains and losses are recorded in earnings in the period they arise.

Net interest expense in the third quarter was $87 million, which contrasted with net interest expense of $57 million in the same quarter of 2001. For the nine months ended September 30, 2002, net interest expense was $229 million, an increase over an expense of $154 million for the same period last year. The increase in net interest expense reflected the higher levels of net debt held by the Company during the quarter and the first nine months of the year compared with the same periods of 2001.

Administrative expenses amounted to $31 million in the third quarter of 2002 compared with $20 million in the same period of 2001. Year-to-date administrative expenses were $75 million and $53 million in 2002 and 2001, respectively. The increases in administrative expenses, both on a quarterly and year to date basis, relate primarily to increased people and technology costs.

The provision for income taxes in the third quarter was $55 million, up from $40 million in the same quarter of last year. The year-to-date provision for income taxes was $152 million, down $238 million from the first nine months of 2001. The year-to-date decrease reflects the impact of lower operating results combined with an adjustment of $20 million to future income taxes resulting from a reduction in the Alberta corporate tax rate. In addition, the 2001 provision for income taxes included $52 million in cash taxes resulting from the gain on the sale of the Jonah Gas Gathering Company.

LIQUIDITY AND CAPITAL RESOURCES

AEC’s cash flow from continuing operations was $728 million in the third quarter compared with $424 million in the same quarter of 2001. Cash flow from continuing operations was $1,307 million for the year to date, in comparison with $1,759 million for the same period of 2001. Weaker energy prices in 2002 were the primary factor contributing to the year-to-date decline.

During the quarter, the Company issued common shares to its parent company for cash consideration of $1.2 billion.

Net capital expenditures of $1,061 million in the quarter included approximately $539 million related to the purchase of producing and non-producing assets in the Jonah field, in southwestern Wyoming. For the nine months ended September 2002, net capital expenditures were $2,659 million and, in addition to the Jonah field purchase, include approximately $420 million related to the purchase of certain Colorado natural gas properties. In comparison, net capital expenditures were $190 million in the third quarter of 2001 and $1,724 million for the nine months ended September 30, 2001, which included the purchase of Ballard Petroleum in the first quarter. The Company’s net investing for the year to date was funded by cash flow of $1,361 million, the issuance of common shares and long-term debt.

On October 16, 2002, the Company announced that it had established October 22, 2002 as the record date for a meeting of holders of its Capital Securities to consider, and if thought advisable, to approve, amendments to the terms of such Capital Securities to provide the Company with the right to call for the early redemption of the Capital Securities with a face value of $430 million.

10

RISK MANAGEMENT

Through the normal course of business, the Company is exposed to market risks associated with fluctuations in commodity prices, foreign exchange rates and interest rates in addition to credit and operational risks.

Exposure to market risks is managed by the Company through the use of various financial instruments. This risk management program is designed to enhance shareholder value by mitigating the volatility associated with commodity prices, exchange rates and interest rates, enhancing the probability of achieving corporate performance targets. As at September 30, 2002, the total unrecognized gain related to financial and physical instruments was $208 million.

The risk of credit losses is minimized through the use of mandated credit policies and procedures designed to ensure that exposures are held within acceptable levels. With the exception of Ecuador oil sales, AEC does not have a significant concentration of credit risk with any single counterparty and bad debts incurred or provided for to date in 2002 are not material. All of the proceeds from the sale of the Company’s crude oil production in Ecuador are received from one marketing company. Accounts receivables on these sales are supported by letters of credit issued by a major international financial institution.

Operational risks are managed through a comprehensive insurance program designed to protect the Company from any significant losses arising from the risk exposures. Safety and environment risks are managed by executing policies and standards that comply with or exceed government regulations and industry standards. In addition, the Company maintains a system that identifies, assesses and controls safety and environmental risk and requires regular reporting to senior management and the Board of Directors.

OUTLOOK

The Company continues to be optimistic about results for the remainder of 2002. Sales for 2002 are forecast to be between 1,565 and 1,615 million cubic feet per day for produced natural gas and between 142,000 and 153,000 barrels per day of oil and natural gas liquids. Volatility in world energy prices is expected to continue through the remainder of the year. The Company’s risk management program is expected to assist in reducing the negative effect in the event of oil market price declines.

Capital investment in core programs is expected to be approximately $3.4 billion before dispositions. It is expected the Company will be able to fund this program largely from cash flow together with proceeds received on the disposition of non-core assets. Expenditures will continue to emphasize anticipated strong near-term production growth, particularly in natural gas, while exploration and development by offshore and international focuses on medium and longer-term value creation.

November 4, 2002

11

Alberta Energy Company Ltd.

1800, 855 – 2nd Street SW, PO Box 2850
Calgary, Alberta  T2P 2S5

November 4, 2002

To:   Canadian Securities Commissions

     In accordance with continuous disclosure obligations of National Instrument 44-102 of the Canadian Securities Administrators, attached hereto for filing are the interest coverage ratios (the “Coverage Ratios”) for Alberta Energy Company Ltd. (“AEC”) for the twelve months ended September 30, 2002. The Coverage Ratios are to be considered as being appended to AEC’s unaudited comparative financial statements for the nine months ended September 30, 2002.

     AEC is making this filing of the Coverage Ratios in connection with its Medium Term Note debenture program, which was established pursuant to a final short form prospectus dated August 2, 2001 that was filed with securities regulatory authorities in all provinces of Canada.

ALBERTA ENERGY COMPANY LTD.

Per:  “Kerry D. Dyte”

Name: Kerry D. Dyte
Title: Corporate Secretary

Alberta Energy Company Ltd.

Financial Coverage on Long-Term Debt

($ millions, except ratios)

Interest Coverage on Long-Term Debt (earnings basis) (1)

		12 months ended			12 months ended
		December 31, 2001			September 30, 2002
Net earnings			824	(A)		323	(A)
Add: Interest,net			256			330
	Income taxes		443			215
			1,523			868
Interest,net			256			330
Capitalized interest			15			2
			271			332
Interest coverage ratio			5.62			2.61

(A)  Includes gain on sale of assets of $238 for the 12 months ended December 31, 2001 and $50 for September 30, 2002.

Interest Coverage on Long-Term Debt (cash flow basis) (1)

Cash flow from Operations		2,023	1,581
Plus: Interest, net		256	330
	Cash income taxes	357	318
		2,636	2,229
Interest		271	332
Interest coverage ratio		9.72	6.71

(1)  The interest coverage ratios have been calculated without including the annual carrying charges relating to the aggregate principal amount of the Preferred Securities outstanding. If the Preferred Securities were classified as long-term debt, the carrying charges would be included in interest, net. If these annual carrying charges had been included in the calculations, the interest coverage ratios would have been:

	12 months ended		12 months ended
	December 31, 2001		September 30, 2002
Interest coverage on long-term debt (earnings basis)		4.40		2.23
Interest coverage on long-term debt (cash flow basis)		7.61		5.72

November 4, 2002

The Securities Commission or
        Similar Authority in each of the
        Provinces of Canada

Dear Sirs

Re: Alberta Energy Company Ltd.

We are the auditors of above Company and under date of February 8, 2002 we reported on the following financial statements of the Company incorporated by reference in the Short Form Prospectus dated August 2, 2001 relating to the issue and sale of $500,000,000 of Medium Term Note Debentures and in the Short Form Prospectus dated August 22, 2000 relating to the issue and sale of US$1,000,000,000 of debt securities (collectively, the “Prospectuses”):

• Balance sheets as at December 31, 2001 and 2000;

• Consolidated statements of earnings, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2001.

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

• Consolidated condensed balance sheet as at September 30, 2002;

• Consolidated statements of earnings, retained earnings and cash flows for the three and nine months ended September 30, 2002 and 2001.

We have not audited any financial statements of the Company as at any date or for any period subsequent to December 31, 2001. Although we have performed an audit for the year ended December 31, 2001, 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, 2001 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 an opinion on the above-mentioned 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, 2001.

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and other members of the worldwide PricewaterhouseCoopers organization.

We have, however, performed a review of the unaudited interim consolidated financial statements of the Company as at September 30, 2002 and for the three and nine months ended September 30, 2002 and 2001. We performed our review in accordance with Canadian generally accepted standards for a review of interim financial statements by an entity’s auditor. 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 is substantially less in scope than an audit, whose objective is the expression of an opinion regarding the financial statements. 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

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.

ALBERTA ENERGY COMPANY LTD.
(Registrant)

By:  /s/ Linda Mackid

Name: Linda Mackid
Title: Assistant Corporate Secretary

Date: November 5, 2002

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