Edgar Filing: ENBRIDGE INC

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

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

Dated November 3, 2005
Commission file number 0-21080

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)


Canada (State or other jurisdiction of incorporation or organization)		None (I.R.S. Employer Identification No.)

3000, 425 – 1^st Street S.W.
Calgary, Alberta, Canada T2P 3L8
(Address of principal executive offices and postal code)

(403) 231-3900
(Registrants telephone number, including area code)

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

Form 20-F o Form 40-F þ

[Indicate by check mark 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 þ

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 33-77022) AND FORM F-10 (FILE NO. 333-122526) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following document is being submitted herewith:

•

Press Release dated November 3, 2005.

•

Interim Report to Shareholders for the nine months ended September 30, 2005.

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.


	ENBRIDGE INC. (Registrant)
Date: November 3, 2005	By:	/s/ “Alison T. Love”
		Alison T. Love
		Vice President & Corporate Secretary

NEWS RELEASE

Enbridge reports strong nine-month earnings and increases dividend by 15%

Highlights

	•		Adjusted operating earnings increase 11% for the nine months ended September 30, 2005

	•		Adjusted operating earnings for the third quarter increase 17% to $73.9 million

	•		Continued progress on multiple liquids pipeline development projects

	•		Recent hurricanes cause temporary volume declines for offshore gas transmission assets

	•		Board of Directors approves an increase in common share dividends of 15%

CALGARY, Alberta, November 3, 2005 — “This has been another strong quarter for Enbridge, notwithstanding the effects of two severe hurricanes and the resulting stress on our employees” said Patrick D. Daniel, President & Chief Executive Officer of Enbridge Inc. “While our offshore assets will continue to be negatively affected in the fourth quarter, Enbridge’s full year performance and longer term outlook remain very bright, due to the diversity and quality of our asset base. Enbridge continues to anticipate full year 2005 adjusted operating earnings will be within the previously noted $1.60 to $1.65 per share range.”

“Enbridge continues to actively develop and advance an unprecedented number of organic growth projects totaling more than $8 billion. During a busy quarter, we achieved some key milestones, evidencing our progress. We announced founding shipper agreements underpinning our $400 million Waupisoo oilsands feeder pipeline to Edmonton and successfully completed our shipper open season processes for the $1.3 billion Southern Access pipeline expansion to the U.S. Midwest and the $1.7 billion Gateway import condensate pipeline from Kitimat, B.C. to Edmonton, Alberta”.

Mr. Daniel concluded, “As a result of this tremendous portfolio of opportunities, we are very confident that we will achieve organic growth rates on average over the next five years of 6% or more. We will continue to pursue accretive acquisitions on an opportunistic basis, as a supplementary source of growth, acknowledging that the current M&A price environment is challenging.”

Based on this positive outlook, and taking into consideration the increased attractiveness that many investors are assigning to dividend income, the Board of Directors has approved a revised dividend policy for Enbridge. Going forward, Enbridge will target to pay out approximately 60%-70% of earnings, an increase from the recent 50% to 60% target range. The Board also determined that it would be appropriate to adjust the quarterly dividend immediately to bring it into alignment with the new target range. Enbridge retains ample balance sheet capacity, together with internally generated funds and access to capital markets, to maintain our strong credit rating and fund our large portfolio of organic growth projects as they are put in place, plus opportunistic acquisitions. The resulting combination of strong long term growth and favourable near term cash payout will provide our investors with an attractive value proposition and one that is unparalleled in our industry.”

On November 2, 2005, the Enbridge Board of Directors declared quarterly dividends of $0.2875 per common share reflecting a 15% increase and $0.34375 per Series A Preferred Share. Both dividends are payable on December 1, 2005 to shareholders of record on November 15, 2005.

Earnings applicable to common shareholders are $382.0 million for the nine months ended September 30, 2005, or $1.13 per share, compared with $540.5 million, or $1.62 per share, in 2004. The $158.5 million decrease in earnings is primarily the result of the prior year including an after tax $97.8 million gain on the sale of AltaGas Trust Units as well as the resulting absence of earnings from this investment in 2005. In addition, the 2004 earnings were higher as a result of the previously announced change in the year-end of the gas distribution operations that creates a lack of comparability between periods. Positive factors in 2005 include the earnings contribution from the recently acquired Enbridge Offshore Pipelines and lower interest expense.

Earnings applicable to common shareholders are $67.8 million for the three months ended September 30, 2005, or $0.20 per share, compared with $179.7 million, or $0.54 per share, in 2004. The third quarter results reflect similar factors as the nine month results with the largest item being the $97.8 million gain on the sale of AltaGas in the prior year.

Consolidated Earnings


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004

Liquids Pipelines		61.6			61.6			168.2			167.9
Gas Pipelines		9.9			12.3			46.9			39.2
Sponsored Investments		11.4			19.5			44.3			49.5
Gas Distribution and Services¹		(20.8	)		86.1			109.9			296.5
International		21.0			16.1			59.6			53.6
Corporate		(15.3	)		(15.9	)		(46.9	)		(66.2	)

		67.8			179.7			382.0			540.5

Consolidated earnings for 2005 reflect earnings from Enbridge Gas Distribution (EGD), Noverco and Other Gas Distribution Operations on a calendar year basis for the three and nine months ended September 30, 2005; whereas, earnings for 2004 reflect earnings from EGD, Noverco and Other Gas Distribution Operations on a quarter-lag basis for the three and nine months ended June 30, 2004. Effective December 31, 2004, EGD changed its fiscal year-end for financial reporting purposes from September 30 to December 31. Accordingly, the 2004 earnings from EGD, Noverco and Other Gas Distribution Operations are not comparable to earnings for 2005. Reconciliations are provided below.

Non-GAAP Measures

This news release contains references to adjusted operating earnings, which represent earnings applicable to common shareholders adjusted for non-operating factors. This is not a measure that has a standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and is not considered a GAAP measure. Therefore, this measure may not be comparable to a similar measure presented by other issuers. Management believes that the presentation of adjusted operating earnings provides useful information to investors and shareholders as it provides clear earnings trends and increased predictive value.


	Three months ended					Nine months ended
(millions of Canadian dollars)	September 30,					September 30,
	2005		2004			2005			2004

Consolidated GAAP earnings		67.8		179.7			382.0			540.5
Non-operating factors and variances as per table below		6.1		(116.7	)		(7.5	)		(203.4	)

Adjusted Operating Earnings		73.9		63.0			374.5			337.1

Significant non-operating factors and variances (after tax) affecting consolidated earnings are as follows:


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004

Sponsored Investments
Dilution gains on EEP unit issuance		—			6.7			4.6			7.6
EEP non-cash derivative fair value losses		(5.9	)		—			(5.9	)		—
Gas Distribution and Services
Quarter lag earnings of EGD, Noverco and other¹		—			(21.7	)		—			157.7
Calendar basis earnings of EGD, Noverco and other¹		—			41.1			—			(89.6	)
Colder/(warmer) than normal weather at EGD		(0.2	)		1.1			1.5			21.3
Elimination of seasonal distribution rates at EGD		—			(8.3	)		—			—
Dilution gain in Noverco (Gaz Metro unit issuance)		—			—			7.3			—
Gain on sale of investment in AltaGas Income Trust		—			97.8			—			97.8
Dilution gain (AltaGas Income Trust)		—			—			—			8.0
Revalue future income taxes due to tax rate changes		—			—			—			0.6


Total significant non-operating factors and variances increasing/(decreasing) earnings		(6.1	)		116.7			7.5			203.4


¹		Effective December 31, 2004, EGD’sfiscal year-end changed from September 30 to December 31 and EGD is no longer consolidated on a quarter-lag basis. In order to compare 2004 earnings to 2005, the 2004 earnings for EGD, Noverco and Other Gas Distribution Operations for the three and nine months ended June 30, 2004, have been eliminated and earnings, for the three and nine months ended September 30, 2004, have been added. Other non-operating factors and variances that affected these businesses in 2004 are for the three and nine months ended September 30, 2004, as was reported in the Company’s fourth quarter results for 2004.

Significant operating factors affecting consolidated earnings in 2005 include the following:

•		Enbridge Offshore Pipelines, acquired December 31, 2004, contributes positive earnings.

•		There are no earnings from AltaGas in 2005 as the investment was sold in 2004.

•		Corporate costs are lower primarily as a result of lower interest expense.

The Company has foreign currency denominated earnings, primarily from U.S. based operations and investments, as well as its Euro investment in CLH. The Company uses long-term derivative contracts to economically hedge a significant portion of the cash distributions related to these long-term investments. However, this does not eliminate the earnings volatility caused by exchange rate differences. During the nine months ended September 30, 2005, the Company received foreign currency denominated cash distributions and settled associated hedge transactions resulting in $9.9 million (2004 — $5.1 million) of incremental cash flows, which is not included in reported earnings.

Liquids Pipelines

Three months ended

Nine months ended

(millions of Canadian dollars)

September 30,

2005

2004

2005

2004

Enbridge System

45.4

47.9

123.8

130.6

Athabasca System

13.1

11.6

36.8

32.6

NW System

2.0

1.8

5.7

5.7

Feeder Pipelines and Other

1.1

0.3

1.9

(1.0

)

61.6

61.6

168.2

167.9

•		Enbridge System earnings include a lower earnings base from the Incentive Tolling Settlement (ITS) component of the Enbridge System reflecting the terms of the ITS memorandum of understanding, recently negotiated with the Canadian Association of Petroleum Producers and filed with the National Energy Board. Also contributing to the earnings variance in the Enbridge System are increased oil losses, predominantly in the first quarter, and higher taxes relating to Terrace.

•		Increased earnings from the Athabasca System are consistent with the overall return underpinning the long-term take or pay contract with its major shipper as well as lower operating costs due to leak remediation in the prior year .

•		The year to date earnings variance in Feeder Pipelines and Other is the result of Federal Energy Regulatory Commission ordered reparations on the Frontier Pipeline recorded in the first quarter of 2004.

Gas Pipelines

Three months ended

Nine months ended

(millions of Canadian dollars)

September 30,

2005

2004

2005

2004

Alliance Pipeline (US)

8.0

8.8

24.4

27.5

Enbridge Offshore Pipelines

(1.7

)

—

10.9

—

Vector Pipeline

3.6

3.5

11.6

11.7

9.9

12.3

46.9

39.2

•		Alliance Pipeline (US) earnings variance primarily reflects the impact of the stronger Canadian dollar in 2005.

•		Enbridge Offshore Pipelines was acquired on December 31, 2004. Hurricanes Katrina and Rita have negatively affected transmission volumes and the results of this business. The quarterly result includes property insurance deductibles as well as lost revenue on various systems prior to the commencement of contingent business interruption insurance coverage. The combined effect of the property damage deductibles and the estimated lost revenue reduced expected third quarter earnings by approximately $10 million.

•		Vector Pipeline earnings reflect the positive effect of continued growth in short haul firm transportation volumes offset by the negative impact of the stronger Canadian dollar in 2005.

Sponsored Investments

Three months ended

Nine months ended

(millions of Canadian dollars)

September 30,

2005

2004

2005

2004

Enbridge Income Fund (EIF)

9.1

6.9

25.8

21.9

Enbridge Energy Partners (EEP)

2.3

5.9

13.9

20.0

Dilution Gains (EEP)

—

6.7

4.6

7.6

11.4

19.5

44.3

49.5

•

The 2005 results from EIF include higher preferred unit distributions as well as higher incentive income consistent with EIF’s cash distribution increases in 2004. EIF’s operating results benefited from enhanced performance at both Alliance Canada and the Saskatchewan System.

•

EEP’s 2005 results reflect a number of factors including positive contributions from natural gas systems offset by lower Lakehead System volumes, a stronger Canadian dollar, a lower ownership interest and $5.9 million (net to Enbridge) of unrealized mark-to-market losses on derivative financial instruments which do not qualify for hedge accounting treatment. While Enbridge believes the hedging strategies are sound economic hedging techniques, they do not qualify for hedge accounting and must be accounted for on a mark-to-market basis through earnings.

•

EEP issued partnership units in 2005 and 2004 and because Enbridge did not fully participate in these offerings, dilution gains resulted.

Gas Distribution and Services


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004

Enbridge Gas Distribution¹		(32.9	)		(22.7	)		55.4			121.2
Noverco¹		1.9			(0.1	)		21.7			28.5
CustomerWorks/ECS		6.6			3.4			18.9			12.6
Other Gas Distribution Operations¹		(1.0	)		1.1			4.9			8.0
Enbridge Gas New Brunswick		1.8			1.1			3.8			2.8
Gas Services		(0.8	)		0.8			(0.9	)		(0.2	)
Aux Sable		2.4			3.9			6.2			3.4
AltaGas Income Trust (investment sold in 2004)		—			0.8			—			21.1
Gain on sale of AltaGas Income Trust Units		—			97.8			—			97.8
Other		1.2			—			(0.1	)		1.3

		(20.8	)		86.1			109.9			296.5


¹		Earnings for 2005 are on a calendar year basis for the three and nine months ended September 30, 2005; whereas earnings for 2004 reflect earnings on a quarter-lag basis for the three and nine months ended June 30, 2004. Effective December 31, 2004, EGD changed its fiscal year-end for financial reporting purposes from September 30 to December 31. Accordingly, the 2004 earnings from EGD, Noverco and Other Gas Distribution Operations are not comparable to earnings for 2005. Reconciliations are provided below.


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004

Enbridge Gas Distribution — as reported		(32.9	)		(22.7	)		55.4			121.2
Significant non-operating factors and variances:
quarter lag earnings ¹		—			22.7			—			(121.2	)
calendar basis earnings ²		—			(36.1	)		—			73.6
warmer/(colder) than normal weather		0.2			(1.1	)		(1.5	)		(21.3	)
elimination of seasonal distribution rate		—			8.3			—			—

		(32.7	)		(28.9	)		53.9			52.3


¹		These earnings are for the three and nine months ended June 30, 2004 and were included in Enbridge’s consolidated earnings for the period ended September 30, 2004.

²		These earnings are for the three and nine months ended September 30, 2004 and were included in Enbridge’s consolidated earnings for the year ended December 31, 2004.

•

EGD’s 2005 regulatory decision eliminated seasonal distribution rates, which were higher in the winter months and lower in the summer months, and replaced them with a uniform annual rate. Commencing in 2005, this shifts a portion of earnings from the winter months to the summer months. The seasonal distribution rate variance, noted in the above table, is the effect of applying the uniform rate to 2004 results and volumes.

•

EGD earnings are consistent with the prior year. The third quarter variance at EGD reflects the timing of various expenses as compared to the forecast cost of service that is included in revenues, and is a reversal of the trend identified in the prior quarter.


	Three months ended					Nine months ended
(millions of Canadian dollars)	September 30,					September 30,
	2005		2004			2005			2004

Noverco — as reported		1.9		(0.1	)		21.7			28.5
Significant non-operating factors and variances:
quarter lag earnings ¹		—		0.1			—			(28.5	)
calendar basis earnings ²		—		(3.7	)		—			11.2
dilution gain in Noverco (Gaz Metro unit issuance)		—		—			(7.3	)		—

		1.9		(3.7	)		14.4			11.2


¹		These earnings are for the three and nine months ended June 30, 2004 and were included in Enbridge’s consolidated earnings for the period ended September 30, 2004.

²		These earnings are for the three and nine months ended September 30, 2004 and were included in Enbridge’s consolidated earnings for the year ended December 31, 2004.

•

During the year, the Company received a $70 million cash dividend from Noverco and recorded a $50 million adjustment for reciprocal dividends, both of which affect the accounting base of the investment and create a net future income tax recovery. Half of the dividend, and the related future income tax recovery, was recorded in the third quarter, resulting in increased earnings compared to the prior year. The net income tax recovery in the nine month period includes the future income tax expense recorded in respect of these items in the second quarter.


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005		2004

Other Gas Distribution Operations — as reported		(1.0	)		1.1			4.9		8.0
Significant non-operating factors and variances:
quarter lag earnings ¹		—			(1.1	)		—		(8.0	)
calendar basis earnings ²		—			(1.3	)		—		4.8

		(1.0	)		(1.3	)		4.9		4.8


¹		These earnings are for the three and nine months ended June 30, 2004 and were included in Enbridge’s consolidated earnings for the period ended September 30, 2004.

²		These earnings are for the three and nine months ended September 30, 2004 and were included in Enbridge’s consolidated earnings for the year ended December 31, 2004.

International


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004

CLH		14.2			10.9			39.8			35.4
OCENSA/CITCol		8.2			7.9			24.4			23.8
Other		(1.4	)		(2.7	)		(4.6	)		(5.6	)

		21.0			16.1			59.6			53.6

•

The Company’s international investments continue to show strong performance. Earnings from CLH during the third quarter are higher due to an increase in average tariffs and lower operating costs.

Corporate


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004
Corporate		(15.3	)		(15.9	)		(46.9	)		(66.2	)

•

The decrease in corporate costs is primarily the result of lower interest expense in 2005 and higher business development activity in 2004. The lower interest expense is a function of lower interest rates and lower average debt balances, including the December 2004 redemption of preferred securities with the proceeds from the AltaGas disposition.

Conference Call

Enbridge will hold a conference call on November 3, 2005 at 9:30 a.m. Eastern time (7:30 a.m. Mountain time) to discuss the third quarter 2005 results. The call can be accessed at 1-800-299-7635, pass code of 11068310, and will be audio webcast live at www.enbridge.com/investor. An audio replay will be available shortly thereafter at 1-888-286-8010 using the access code 18670455; in addition, the webcast replay and transcript will be available on the website, later in the day.

The unaudited interim consolidated financial statements and MD&A, which contain additional notes and disclosures, are available on the Enbridge website.

Enbridge Inc. is a leader in energy transportation and distribution in North America and internationally. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids pipeline system. The Company also has international operations and a growing involvement in the natural gas transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company, and provides distribution services in Ontario, Quebec, New Brunswick and New York State; and is developing a gas distribution system for the Province of New Brunswick. Enbridge employs approximately 4,000 people, primarily in Canada, the United States and South America. Enbridge’s common shares trade on the Toronto Stock Exchange in Canada and on the New York Stock Exchange in the United States under the symbol ENB. Information about Enbridge is available on the Company’s website at www.enbridge.com.

Certain information provided in this news release constitutes forward-looking statements. The words “anticipate”, “expect”, “project”, “estimate”, “forecast” and similar expressions are intended to identify such forward-looking statements. Although Enbridge believes that these statements are based on information and assumptions which are current, reasonable and complete, these statements are necessarily subject to a variety of risks and uncertainties pertaining to operating performance, regulatory parameters, weather, economic conditions and commodity prices. You can find a discussion of those risks and uncertainties in our Canadian securities filings and American SEC filings. While Enbridge makes these forward-looking statements in good faith, should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. Enbridge assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Enbridge Contacts:


*Media*		*Investment Community*
Jim Rennie		Bob Rahn
(403) 231-3931		(403) 231-7398
E-mail: jim.rennie@enbridge.com		E-mail: bob.rahn@enbridge.com

ENBRIDGE INC.
HIGHLIGHTS¹


(unaudited; millions of Canadian dollars	Three months ended						Nine months ended
except per share amounts)	September 30,						September 30,
	2005			2004			2005			2004
FINANCIAL
Earnings Applicable to Common Shareholders
Liquids Pipelines		61.6			61.6			168.2			167.9
Gas Pipelines		9.9			12.3			46.9			39.2
Sponsored Investments		11.4			19.5			44.3			49.5
Gas Distribution and Services		(20.8	)		86.1			109.9			296.5
International		21.0			16.1			59.6			53.6
Corporate		(15.3	)		(15.9	)		(46.9	)		(66.2	)
67.8 179.7 382.0 540.5
		67.8			179.7			382.0			540.5

Cash Provided By Operating Activities
Earnings plus charges/(credits) not affecting cash		251.3			188.4			916.1			796.3
Changes in operating assets and liabilities		(350.2	)		229.8			6.2			513.9

		(98.9	)		418.2			922.3			1,310.2

Common Share Dividends		86.9			79.0			260.7			236.6

Earnings per Common Share		0.20			0.54			1.13			1.62

Diluted Earnings per Common Share		0.20			0.54			1.12			1.61

Dividends per Common Share		0.2500			0.2288			0.7500			0.6863

Weighted Average Common Shares Outstanding (millions)								337.2			334.2

Diluted Weighted Average Common Shares Outstanding (millions)								340.7			337.1


OPERATING
Liquids Pipelines²
Deliveries (thousands of barrels per day)		1,908			2,110			1,979			2,125
Barrel miles (billions)		168			189			513			565
Average haul (miles)		959			975			949			971
Gas Distribution and Services³
Volumes (billion cubic feet)		45			76			309			398
Number of active customers (thousands)		1,782			1,737			1,782			1,737
Degree day deficiency⁴
Actual		23			723			2,476			3,733
Forecast based on normal weather		60			714			2,500			3,521

^1.		Financial and operating highlights of Gas Distribution and Services for 2004 reflect the results of Enbridge Gas Distribution (EGD) and other gas distribution operations on a one-quarter lag basis for the three and nine months ended June 30, 2004. For 2005, as a result of EGD’s change in fiscal year end from September 30 to December 31, financial and operating highlights reflect the results of EGD and other gas distribution operations for the three and nine months ended September 30, 2005.

^2.		Liquids Pipelines operating highlights include the statistics of the 11.2% owned Lakehead System and other wholly-owned liquid pipeline operations.

^3.		Gas Distribution and Services volumes and the number of active customers are derived from the aggregate system supply and direct purchase gas supply arrangements.

^4.		Degree-day deficiency is a measure of coldness. It is calculated by accumulating for each day in the period the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Toronto area.

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars, except per share amounts)	2005			2004			2005			2004

Revenues
Commodity sales		1,142.1			1,202.1			4,108.0			4,070.7
Transportation		430.7			396.6			1,439.3			1,258.0
Energy services		84.3			16.8			238.0			155.5

		1,657.1			1,615.5			5,785.3			5,484.2

Expenses
Commodity costs		1,076.9			1,114.0			3,789.9			3,634.2
Operating and administrative		267.4			217.6			782.0			657.4
Depreciation		141.2			115.1			427.5			340.6

		1,485.5			1,446.7			4,999.4			4,632.2

Operating Income		171.6			168.8			785.9			852.0
Investment and Other Income		21.1			51.7			143.9			223.1
Gain on Sale of Investment in AltaGas Income Trust Units		—			121.5			—			121.5
Interest Expense		(133.0	)		(119.7	)		(402.4	)		(366.9	)

		59.7			222.3			527.4			829.7
Income Taxes		9.8			(40.8	)		(140.3	)		(284.0	)

Earnings		69.5			181.5			387.1			545.7
Preferred Share Dividends		(1.7	)		(1.8	)		(5.1	)		(5.2	)

Earnings Applicable to Common Shareholders		67.8			179.7			382.0			540.5


Earnings Per Common Share		0.20			0.54			1.13			1.62


Diluted Earnings Per Common Share		0.20			0.54			1.12			1.61

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS


	Nine months ended
	September 30,
(unaudited; millions of Canadian dollars)	2005			2004

Retained Earnings at Beginning of Period		1,840.9			1,511.4
Earnings Applicable to Common Shareholders		382.0			540.5
Common Share Dividends		(260.7	)		(236.6	)
Dividends Paid to Reciprocal Shareholder		8.1			—
Dividend Reclassification Adjustment (Note 3)		51.2			—

Retained Earnings at End of Period		2,021.5			1,815.3

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars)	2005			2004			2005			2004

Cash Provided By Operating Activities
Earnings		69.5			181.5			387.1			545.7
Charges/(credits) not affecting cash
Depreciation		141.2			115.1			427.5			340.6
Equity earnings less than/(in excess of) cash distributions		82.8			1.5			61.3			(53.6	)
Gain on reduction of ownership interest		—			(17.3	)		(15.6	)		(29.6	)
Gain on sale of investment in AltaGas Income Trust Units		—			(121.5	)		—			(121.5	)
Future income taxes		(44.5	)		(7.3	)		40.5			74.7
Other		2.3			36.4			15.3			40.0
Changes in operating assets and liabilities		(350.2	)		229.8			6.2			513.9

		(98.9	)		418.2			922.3			1,310.2

Investing Activities
Acquisitions		(28.3	)		—			(86.4	)		(17.4	)
Changes in long-term investments		(0.3	)		(0.7	)		(62.1	)		(16.9	)
Additions to property, plant and equipment		(141.5	)		(97.4	)		(341.0	)		(251.6	)
Sale of investment in AltaGas Income Trust Units		—			251.4			—			251.4
Changes in construction payable		(2.1	)		0.9			(2.4	)		(2.2	)
Changes in long-term notes receivable		0.5			—			(0.1	)		—

		(171.7	)		154.2			(492.0	)		(36.7	)

Financing Activities
Net change in short-term borrowings and short-term debt		377.2			(434.4	)		(332.6	)		(1,017.1	)
Non-recourse short-term debt of joint ventures		(6.5	)		—			5.4			(5.0	)
Long-term debt issues		—			—			620.1			300.0
Long-term debt repayments		—			—			(396.9	)		(250.0	)
Non-recourse long-term debt repaid by joint ventures		(2.4	)		—			(54.8	)		(24.5	)
Non-recourse long-term debt issued by joint ventures		—			—			6.8			—
Non-controlling interests		7.4			1.6			(4.5	)		(0.3	)
Common shares issued		7.5			7.4			46.9			31.7
Preferred share dividends		(1.7	)		(1.8	)		(5.1	)		(5.2	)
Common share dividends		(86.9	)		(79.0	)		(260.7	)		(236.6	)

		294.6			(506.2	)		(375.4	)		(1,207.0	)

Increase in Cash		24.0			66.2			54.9			66.5
Cash at Beginning of Period		136.4			104.4			105.5			104.1

Cash at End of Period		160.4			170.6			160.4			170.6

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	September 30,			December 31,
(unaudited; millions of Canadian dollars)	2005			2004

Assets
Current Assets
Cash		160.4			105.5
Accounts receivable and other		1,295.4			1,451.9
Inventory		1,042.5			791.6

		2,498.3			2,349.0
Property, Plant and Equipment, net		10,265.2			9,066.5
Long-Term Investments		1,809.0			2,278.3
Receivable from Affiliate		174.0			171.7
Deferred Amounts and Other Assets		856.7			729.2
Goodwill		357.7			31.5
Intangible Assets		238.9			133.9
Future Income Taxes		147.0			145.0

		16,346.8			14,905.1


Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings		742.8			650.6
Accounts payable and other		1,408.7			1,275.9
Interest payable		71.7			83.8
Current maturities and short-term debt		541.2			703.9
Current portion of non-recourse long-term debt		76.1			30.2

		2,840.5			2,744.4
Long-Term Debt		5,998.1			6,053.3
Non-Recourse Long-Term Debt		1,634.9			665.2
Other Long-Term Liabilities		93.6			151.8
Future Income Taxes		944.8			797.3
Non-Controlling Interests		672.3			514.9

		12,184.2			10,926.9
Shareholders’ Equity
Share capital
Preferred shares		125.0			125.0
Common shares		2,329.3			2,282.4
Contributed surplus		8.4			5.4
Retained earnings		2,021.5			1,840.9
Foreign currency translation adjustment		(185.9	)		(139.8	)
Reciprocal shareholding		(135.7	)		(135.7	)

		4,162.6			3,978.2

		16,346.8			14,905.1

SEGMENTED INFORMATION

Three months ended September 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

222.8

83.9

63.3

1,284.3

2.8

—

1,657.1

Commodity costs

—

(1,076.9

)

—

(1,076.9

)

Operating and administrative

(76.8

)

(25.7

)

(15.4

)

(139.5

)

(3.6

)

(6.4

)

(267.4

)

Depreciation

(37.0

)

(21.9

)

(17.8

)

(62.7

)

(0.2

)

(1.6

)

(141.2

)

Operating income

109.0

36.3

30.1

5.2

(1.0

)

(8.0

)

171.6

Investment and other income

0.8

0.3

0.4

(4.4

)

23.3

0.7

21.1

Interest and preferred equity charges

(24.5

)

(19.9

)

(15.2

)

(44.6

)

—

(30.5

)

(134.7

)

Income taxes

(23.7

)

(6.8

)

(3.9

)

23.0

(1.3

)

22.5

9.8

Earnings applicable to common shareholders

61.6

9.9

11.4

(20.8

)

21.0

(15.3

)

67.8

Three months ended September 30, 2004


										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of Canadian dollars)	Pipelines			Pipelines			Investments			and Services¹			International			Corporate			Consolidated

Revenues		221.6			66.7			—			1,320.1			7.1			—			1,615.5
Commodity costs		—			—			—			(1,114.0	)		—			—			(1,114.0	)
Operating and administrative		(70.7	)		(13.5	)		—			(114.6	)		(9.8	)		(9.0	)		(217.6	)
Depreciation		(36.0	)		(16.5	)		—			(61.3	)		(0.4	)		(0.9	)		(115.1	)

Operating income		114.9			36.7			—			30.2			(3.1	)		(9.9	)		168.8
Investment and other income		0.7			0.1			36.0			(1.9	)		19.6			(2.8	)		51.7
Gain on sale of investment		—			—			—			121.5			—			—			121.5
Interest and preferred equity charges		(25.9	)		(16.4	)		—			(40.6	)		—			(38.6	)		(121.5	)
Income taxes		(28.1	)		(8.1	)		(16.5	)		(23.1	)		(0.4	)		35.4			(40.8	)

Earnings applicable to common shareholders		61.6			12.3			19.5			86.1			16.1			(15.9	)		179.7

Nine months ended September 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

648.7

278.7

185.3

4,664.3

8.3

—

5,785.3

Commodity costs

—

(3,789.9

)

—

(3,789.9

)

Operating and administrative

(228.0

)

(70.0

)

(43.5

)

(413.5

)

(11.7

)

(15.3

)

(782.0

)

Depreciation

(110.7

)

(70.0

)

(53.2

)

(188.3

)

(0.8

)

(4.5

)

(427.5

)

Operating income

310.0

138.7

88.6

272.6

(4.2

)

(19.8

)

785.9

Investment and other income

(0.4

)

1.6

31.2

20.8

66.2

24.5

143.9

Interest and preferred equity charges

(73.0

)

(62.6

)

(46.5

)

(131.9

)

—

(93.5

)

(407.5

)

Income taxes

(68.4

)

(30.8

)

(29.0

)

(51.6

)

(2.4

)

41.9

(140.3

)

Earnings applicable to common shareholders

168.2

46.9

44.3

109.9

59.6

(46.9

)

382.0

Nine months ended September 30, 2004


										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of Canadian dollars)	Pipelines			Pipelines			Investments			and Services ¹			International			Corporate			Consolidated

Revenues		646.5			206.4			—			4,608.1			23.2			—			5,484.2
Commodity costs		—			—			—			(3,634.2	)		—			—			(3,634.2	)
Operating and administrative		(219.9	)		(41.9	)		—			(347.4	)		(28.5	)		(19.7	)		(657.4	)
Depreciation		(107.7	)		(50.4	)		—			(178.8	)		(1.3	)		(2.4	)		(340.6	)

Operating income		318.9			114.1			—			447.7			(6.6	)		(22.1	)		852.0
Investment and other income		1.7			0.5			86.8			57.4			61.9			14.8			223.1
Gain on sale of investment		—			—			—			121.5			—			—			121.5
Interest and preferred equity charges		(76.3	)		(50.4	)		—			(127.3	)		(0.1	)		(118.0	)		(372.1	)
Income taxes		(76.4	)		(25.0	)		(37.3	)		(202.8	)		(1.6	)		59.1			(284.0	)

Earnings applicable																				—
to common shareholders		167.9			39.2			49.5			296.5			53.6			(66.2	)		540.5


1.		Gas Distribution and Services results for 2004 were consolidated on a one-quarter-lag basis and therefore reflect the three and nine month periods ended June 30, 2004. Starting at the end of 2004, EGD changed its fiscal year end from September 30 to December 31. Therefore, the quarter lag basis of consolidation was eliminated. Gas Distribution and Services results for 2005 reflect the three and nine month periods ended September 30, 2005.

Enbridge Inc.
Management’s Discussion & Analysis
For the Three and Nine Months Ended September 30, 2005
Dated November 2, 2005

This Management’s Discussion and Analysis should be read in conjunction with the unaudited interim consolidated financial statements of Enbridge Inc. as at and for the three and nine months ended September 30, 2005.

Consolidated Earnings


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004
Liquids Pipelines		61.6			61.6			168.2			167.9
Gas Pipelines		9.9			12.3			46.9			39.2
Sponsored Investments		11.4			19.5			44.3			49.5
Gas Distribution and Services¹		(20.8	)		86.1			109.9			296.5
International		21.0			16.1			59.6			53.6
Corporate		(15.3	)		(15.9	)		(46.9	)		(66.2	)

		67.8			179.7			382.0			540.5


¹		Consolidated earnings for 2005 reflect earnings from Enbridge Gas Distribution (EGD), Noverco and Other Gas Distribution Operations on a calendar year basis for the three and nine months ended September 30, 2005; whereas, earnings for 2004 reflect earnings from EGD, Noverco and Other Gas Distribution Operations on a quarter lag basis for the three and nine months ended June 30, 2004. Effective December 31, 2004, EGD changed its fiscal year-end for financial reporting purposes from September 30 to December 31. Accordingly, the 2004 earnings from EGD, Noverco and Other Gas Distribution Operations are not comparable to earnings for 2005. Reconciliations are provided below.

Certain information provided in this Management’s Discussion and Analysis (MD&A) constitutes forward-looking statements. The words “anticipate”, “expect”, “project”, “estimate”, “forecast” and similar expressions are intended to identify such forward-looking statements. Although Enbridge believes that these statements are based on information and assumptions which are current, reasonable and complete, these statements are necessarily subject to a variety of risks and uncertainties pertaining to operating performance, regulatory parameters, weather, economic conditions and commodity prices. You can find a discussion of those risks and uncertainties in our Canadian securities filings and American SEC filings. While Enbridge makes these forward-looking statements in good faith, should one or more of these risks or uncertainties materialize, or should

-1-

underlying assumptions prove incorrect, actual results may vary significantly from those expected. Enbridge assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Significant non-operating factors and variances (after tax) affecting consolidated earnings are as follows:


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004

Sponsored Investments
Dilution gains on the issue of EEP units		—			6.7			4.6			7.6
EEP non-cash derivative fair value losses		(5.9	)		—			(5.9	)		—
Gas Distribution and Services
Quarter lag earnings for EGD and others¹		—			(21.7	)		—			157.7
Calendar basis earnings for EGD and others¹		—			41.1			—			(89.6	)
Colder/(warmer) than normal weather at EGD		(0.2	)		1.1			1.5			21.3
Elimination of seasonal distribution rates at EGD		—			(8.3	)		—			—
Dilution gain in Noverco (Gaz Metro unit issuance)		—			—			7.3			—
Gain on sale of investment in AltaGas Income Trust		—			97.8			—			97.8
Dilution gain (AltaGas Income Trust)		—			—			—			8.0
Revalue future income taxes due to tax rate changes		—			—			—			0.6


Total significant non-operating factors and variances increasing/(decreasing) earnings		(6.1	)		116.7			7.5			203.4


¹		Effective December 31, 2004, EGD’sfiscal year-end changed from September 30 to December 31 and EGD is no longer consolidated on a quarter lag basis. In order to compare 2004 earnings to 2005, the 2004 earnings for EGD, Noverco and Other Gas Distribution Operations for the three and nine months ended June 30, 2004, have been eliminated and earnings for the three and nine months ended September 30, 2004, have been added. Other non-operating factors and variances that affected these businesses in 2004 are for the three and nine months ended September 30, 2004.

Significant operating factors affecting consolidated earnings in 2005 include the following:

•

Enbridge Offshore Pipelines, acquired December 31, 2004, contributes positive earnings.

•

There are no earnings from AltaGas in 2005 as the investment was sold in 2004.

•

Corporate costs are lower primarily as a result of lower interest expense.

-2-

RECENT DEVELOPMENTS

U.S. Gulf Coast Hurricanes

Enbridge Offshore Pipelines, a wholly owned subsidiary, has interests in five pipeline corridors in the Gulf of Mexico which were recently affected, to varying degrees, by Hurricane Katrina and Hurricane Rita. As of October 24, 2005, the pipelines were transporting approximately 1,500,000 decatherms per day (Dth/d) compared with the pre-hurricane rate of approximately 2,700,000 Dth/d. The impact on each corridor is described below.

The Mississippi Canyon Corridor was in the direct path of Hurricane Katrina and is still not operating. Minor damage to the Enbridge facilities was isolated primarily to onshore electrical, control and measurement equipment. Repair to onshore facilities and subsea inspection of the underwater pipeline is currently underway. Two key production source platforms and the Venice gas processing plant, all owned by others, were damaged. As of October 24, 2005, no volumes are moving through the Mississippi Canyon Corridor but the Mississippi Canyon pipeline expects to be ready to receive and deliver gas by November 7, 2005 with some liquid handling constraints and limited delivery points being available. Approximately 350,000 Dth/d or two thirds of the pre-Katrina throughput level is expected to be back on line in November. Repairs to upstream and downstream infrastructure will allow throughput to fully recover in 2006.

Hurricane Katrina caused minimal or no damage to assets in the Destin Corridor. However, upstream and downstream oil and natural gas liquids pipelines facilities owned by others experienced damage and were not operational until mid-October. Operations have now been restored with production throughput continuing to increase as repairs of non-Enbridge facilities are completed. As of October 24, 2005, volumes on the Destin Corridor were up to 880,000 Dth/d which is approximately 95% of the pre-hurricane level.

Hurricanes Katrina and Rita caused no material damage in the Green Canyon Corridor and volumes have been unaffected by the hurricanes.

The Garden Banks and Stingray Corridors were in the direct path of Hurricane Rita. In these corridors, there was minimal damage to the Enbridge owned offshore pipelines and platform facilities.

On the Garden Banks Corridor, volumes as of October 24, 2005 were at approximately 300,000 Dth/d or 75% of pre-hurricane throughput levels. Flows are expected to return to pre-hurricane levels in early November when repairs to an upstream producer gathering line are completed.

Due to the storm surge flooding, the electrical, control equipment and office buildings of the onshore Stingray liquids separation, dehydration and compression facilities require repairs which, the Company believes will be completed by year end. As of October 24, 2005, Stingray was rerouting approximately 70,000 to 100,000 Dth/d to an offshore interconnect with a third party pipeline. Volumes delivered to this offshore interconnect are expected to increase to between 150,000 to 200,000 Dth/d with early November repair to downstream infrastructure currently curtailing flow on the third party pipeline. Volumes on the Stingray pipeline are expected to return to pre-hurricane levels by year-end following completion of repairs to the Stingray onshore plant facility.

Hurricane Rita caused no material incremental damage to the Mississippi Canyon and Destin Corridors.

As a result of the hurricanes, Enbridge estimates that 2005 earnings will be negatively impacted by approximately $15 million to $20 million and 2006 earnings will likely also be negatively impacted although to a much lesser degree. The estimates are subject to a number of factors including ongoing damage assessments, interconnecting production and downstream pipeline and processing availability.

-3-

Incentive Tolling Settlement

On June 23, 2005, Enbridge and the Canadian Association of Petroleum Producers (CAPP) approved a Memorandum of Understanding (MOU) setting out the key terms of a new incentive tolling settlement (ITS). The new ITS is effective for January 1, 2005 to December 31, 2009 and defines the methodology for calculating tolls on the core component of the Enbridge Mainline System in Canada. The ITS excludes Line 8, Line 9, and the SEP I, SEP II and Terrace expansions, which have separate tolling arrangements.

Under the new ITS, earnings are based on a revenue requirement calculated in reference to the 2004 revenue requirement, adjusted annually for inflation. The costs of income taxes and power are borne by shippers with Enbridge guaranteeing $5 million in power savings and sharing in any power savings beyond the guaranteed amount. Cost savings above a stipulated threshold are shared equally, with Enbridge retaining 50% and 50% credited to shippers. The revenue requirement also includes an $18 million annual pipeline integrity allowance and half of the operating costs associated with new service metrics, described below. The revenue requirement is adjusted for certain events qualifying as non-routine adjustments. The new ITS continues the throughput protection provisions of the previous ITS, ensuring the Company is insulated from negative volume fluctuations beyond its control.

The new ITS provides Enbridge with the opportunity to increase earnings by achieving performance targets under new quality and predictability metrics, collectively referred to as service metrics, and reliability metric provisions. The service metrics establish financial bonuses and penalties for prescribed performance targets related to crude oil quality management and predictability of scheduled deliveries. The bonuses and penalties for the service metrics are limited to a maximum of $10 million after tax in 2005, escalating to $15 million in each of 2006 and 2007, and to $20 million in each of 2008 and 2009.

The reliability metric provides for bonuses and penalties associated with optimization of system capacity, which are calculated relative to an annual target capacity baseline on a monthly basis. If the Company’s performance is below the target, it is charged a penalty of $200,000 after tax per percentage point for each month that performance is below the target. If the Company’s performance exceeds the target, it earns $500,000 per percentage point for each month that performance is above the target. Practical constraints around pipeline capacity would limit the bonus for the reliability metric to approximately $12 million per year and penalties are limited to $10 million per year.

The National Energy Board (NEB) has approved the interim tolls reflecting the terms of the MOU and the Company anticipates filing the final agreement with the NEB in the fourth quarter of 2005.

Gateway Project

As part of the Gateway Project, Enbridge plans to build a condensate import pipeline from Canada’s west coast to Edmonton, Alberta, which would provide transportation for offshore condensate supply. The 16-inch condensate import pipeline is expected to cost approximately $1.7 billion on a stand-alone basis. Based on the results of the Open Season, which suggested that shippers would support the pipeline, Enbridge plans to increase the expected diameter of the pipeline from 16 inches to 20 inches. Enbridge has also offered condensate line shippers the option to participate, as partners, in the ownership of the pipeline. Final commitment amounts and agreements, as well as equity participation agreements, remain under discussion with individual shippers.

The Gateway Project also includes a crude oil export pipeline, which would transport crude oil from Edmonton to the Canadian west coast. The crude oil export pipeline is expected to cost approximately $2.5 billion on a stand-alone basis and, if both parts of the project proceed together, total savings of approximately $550 million could be realized. Enbridge is conducting a separate Open Season for the crude oil export pipeline which commenced in October 2005.

-4-

The decision to proceed with either pipeline is subject to commercial considerations, including satisfactory completion of shipper agreements, environmental assessment as well as public and Aboriginal consultation. If the Project proceeds, construction could begin as early as 2008 with a target in-service date early in 2010.

Southern Access Mainline Expansion and Extension Program

The Company and Enbridge Energy Partners (EEP) are planning an expansion of the Enbridge Mainline System from Hardisty, Alberta to Chicago, Illinois, and a possible new extension from the Chicago area to hubs at Wood River and Patoka, Illinois. Enbridge would undertake the approximately US$320 million extension, which would involve the construction of a new 30-inch diameter, 300,000 barrels per day (bpd) pipeline. Enbridge would also undertake the Canadian portion of the expansion and EEP, Enbridge’s 11.2%-owned equity investment, would undertake the U.S. expansion.

During the Open Season, in the third quarter of 2005, shippers provided letters of support, endorsing the need to proceed with all three phases of the expansion, which would add a total of 400,000 bpd of capacity. The cost of the expansion would be approximately US$135 million to Enbridge for the Canadian portion and approximately US$880 million to EEP for the U.S. portion. The cost of the expansion could be reduced by approximately US$120 million providing all three phases of the expansion were undertaken as a single project.

Finalization of CAPP support, as well as regulatory approvals, are immediate expansion program milestones. Detailed discussions with interested shippers regarding project design for the extension are currently underway to allow a binding Open Season to proceed in the fourth quarter of 2005. Assuming all necessary approvals and other contingencies are satisfied, the complete program could be in service as early as 2009.

Waupisoo Pipeline Project

During the third quarter of 2005, Enbridge reached agreement with shippers on long-term shipping commitments on the proposed Waupisoo Pipeline. The 30-inch diameter, 380-kilometer long pipeline will transport crude oil from the Cheecham terminal, currently under construction on the Athabasca Pipeline to Edmonton, Alberta. The initial capacity of the line will be 350,000 bpd and is expandable to a maximum of 600,000 bpd through the addition of pumping units. Capacity commitments are subject to shippers’ final approvals, which are expected during the fourth quarter of 2005. Pending regulatory approvals in 2006, Enbridge will begin construction on the approximately $400 million pipeline in 2007, with an expected in-service date of mid-2008.

Based on interest expressed by oil sands producers, Enbridge is including a 16-inch, 150,000 bpd diluent return line within the scope of the project for public consultation and regulatory approval purposes. The diluent line is expected to cost approximately $200 million and would run from the Edmonton area refinery hub north to the oil sands and would be constructed in conjunction with the Waupisoo crude oil pipeline. Shipping commitments on the diluent line have not been finalized.

Goreway Power Project

As disclosed by the Ontario Power Authority in their October 28, 2005 news release, the Company, in partnership with Sithe Global Power, L.L.C., has been selected by the Ontario Power Authority to enter into negotiations to develop a 900 megawatt gas-fired power generation plant in Brampton, Ontario. The new plant would provide needed electricity to the Western Greater Toronto Area. Enbridge would hold a 25% interest in the project, which would provide the Company with an entry point into the gas-fired power generation business in a geographical area already served by the Company’s largest gas distribution business, EGD.

Neptune Lateral Project

The Company plans to construct and operate both a natural gas lateral and a crude oil lateral to connect the deepwater Neptune oil and gas field in the Green Canyon Corridor to existing Gulf

-5-

pipelines. The laterals are expected to cost approximately US$100 million and will have the capacity to deliver in excess of 200 million cubic feet of gas per day and approximately 50,000 bpd of oil. The laterals represent an extension of Enbridge’s existing Gulf of Mexico infrastructure. Connection of the Neptune oil and gas laterals to the producer-owned production facility is scheduled for the second quarter of 2007 with first production expected by year-end 2007.

Fort Saskatchewan Terminal

Enbridge has entered into agreements to provide terminaling and pipeline services to the Heartland Upgrader, under construction by BA Energy at Fort Saskatchewan, Alberta. Enbridge expects to invest approximately $80 million in new facilities to provide storage services at a new satellite terminal it will develop adjacent to the upgrader and pipeline transportation for the upgrader’s output from the new terminal to the nearby Edmonton terminal and refinery hub. These facilities are expected to be in service in the fourth quarter of 2007.

Spearhead Pipeline

Effective June 1, 2005, the Company acquired the final 10% of the Spearhead Pipeline for US$12.4 million, increasing its ownership to 100%. The Company expects to have the line in service in early 2006.

Two-for-One Stock Split

A two-for-one stock split was approved by shareholders at the May 5, 2005 Annual and Special Meeting. After the stock split, the number of outstanding shares doubled from approximately 174 million to approximately 348 million. Enbridge’s last stock split occurred in 1999. All references to shares and per share amounts in this report incorporate the effect of the stock split.

2006 Rate Application

On March 18, 2005, EGD filed an application with the Ontario Energy Board (OEB) for approval of the 2006 rates, under cost of service. A final decision on this rate application is expected from the OEB during the first quarter of 2006. The key elements of the application are summarized below


	Requested for
Regulatory year ending December 31,	2006

Rate base (millions)	$	3,596.2
Rate of return on rate base		8.33	%
Deemed common equity for regulatory purposes		35.00	%
Rate of return on common equity		10.11	%

Gas Distribution Access Rule (GDAR)

The GDAR, developed by the OEB, mandates that distributors, including EGD, provide gas marketers with the option to consolidate the gas distribution charges to consumers on the marketers’ own bill, forcing the distributor to appoint the marketer as its billing agent. EGD would have to undertake extensive system changes and negotiate new contractual arrangements in order to effect the GDAR directives.

On January 11, 2005, the Ontario Court of Appeal dismissed an appeal, by EGD and Union Gas Limited, of the vendor consolidated billing aspects of the GDAR and upheld the OEB’s authority to enact these aspects of the GDAR. EGD elected not to appeal the Court of Appeal’s decision and has advised the OEB that it is prepared to implement the transactional aspects of the GDAR. On May 9, 2005, the OEB issued a decision on GDAR, which outlined a process to ensure that GDAR is operational by 2006. The decision outlined a number of individual stakeholder sessions to be held in the summer/fall of 2005. Through these sessions, the detailed operational rules will be determined which will allow EGD and Union Gas to change their billing systems to adhere to GDAR.

- 6 -

Should marketers elect to consolidate distribution charges on their own bill, the Company may lose some of the revenue it earns by providing billing services; however, this is not expected to have a material impact on earnings.

Oil Sands Projects — Surmont

Enbridge entered into definitive agreements with ConocoPhillips Surmont Partnership and Total E&P Canada Ltd. (the Surmont Shippers) to provide pipeline transportation services on its Athabasca Pipeline for the Surmont Project starting in mid-2006. Enbridge will construct, own and operate the pipeline and tank facilities required by the Surmont Project, including a diluent lateral, a crude lateral, and tank facilities at the Cheecham terminal on the Athabasca Pipeline. The estimated cost of these facilities is $42 million. The agreements provide for an initial contract volume of up to 50,000 bpd of crude oil with the option to increase the contract volume to up to 220,000 bpd for future phases of production. The agreement covering the dedicated Surmont lateral facilities and the agreement for transportation service on the Athabasca Pipeline are both for an initial term of 25 years, with extension provisions. The Athabasca Pipeline agreement also provides flexibility for the Surmont Shippers to transfer their production to the proposed Waupisoo Pipeline to Edmonton following its planned start-up in mid 2008

Oil Sands Projects — Long Lake

During the first quarter of 2005, the Company entered into definitive agreements with Nexen Inc. and OPTI Canada Inc. (the Long Lake Shippers) to provide pipeline transportation services for the Long Lake oil sands project.

Under the terms of the agreements, Enbridge will construct, own and operate the pipeline and tank facilities required by the Long Lake Project, as well as pipeline laterals and tank facilities at the Cheecham terminal on the Athabasca Pipeline. The estimated cost of these facilities is $40 - $45 million with a planned in-service date in late 2006. Enbridge’s 545 kilometer Athabasca Pipeline will also require capacity expansion from the Cheecham terminal to its mainline terminal at Hardisty, Alberta.

The agreements provide for an initial contract volume of up to 60,000 bpd of crude oil with provisions for increases to the contract volume. The agreement covering the dedicated Long Lake lateral facilities is for a term of 25 years and the agreement for service on the Athabasca Pipeline is for a 50-month term with extension provisions. The agreements also provide flexibility for the Long Lake Shippers to use the Waupisoo Pipeline to move crude oil from the Cheecham terminal to Edmonton.

- 7 -

FINANCIAL RESULTS

Liquids Pipelines
Earnings

Three months ended

Nine months ended

(millions of Canadian dollars)

September 30,

2005

2004

2005

2004

Enbridge System

45.4

47.9

123.8

130.6

Athabasca System

13.1

11.6

36.8

32.6

NW System

2.0

1.8

5.7

5.7

Feeder Pipelines and Other

1.1

0.3

1.9

(1.0

)

61.6

61.6

168.2

167.9

Earnings are $168.2 million for the nine months ended September 30, 2005, consistent with the same period in the prior year. The decrease in earnings from the Enbridge System was more than offset by increases in both Frontier Pipeline earnings, which are included in Feeder Pipelines and Other, and Athabasca System earnings.

Enbridge System earnings include a lower earnings base from the ITS component of Enbridge System reflecting the terms of the ITS MOU, recently negotiated with CAPP and filed with the NEB. Also contributing to the earnings variance in the Enbridge System are increased oil losses, predominantly in the first quarter, and higher taxes relating to Terrace.

Increased earnings from the Athabasca System are consistent with the overall return underpinning the long-term take or pay contract with its major shipper, as well as lower operating costs due to leak remediation in the prior year.

The year to date earnings variance in Feeder Pipelines and Other is the result of Federal Energy Regulatory Commission ordered reparations on the Frontier Pipeline recorded in the first quarter of 2004.

For the three months ended September 30, 2005, earnings are consistent with the prior year and reflect similar offsetting factors as the nine-month results.

Gas Pipelines
Earnings

Three months ended

Nine months ended

(millions of Canadian dollars)

September 30,

2005

2004

2005

2004

Alliance Pipeline (US)

8.0

8.8

24.4

27.5

Enbridge Offshore Pipelines

(1.7

)

—

10.9

—

Vector Pipeline

3.6

3.5

11.6

11.7

9.9

12.3

46.9

39.2

Earnings are $46.9 million for the nine months ended September 30, 2005, compared with $39.2 million for the nine months ended September 30, 2004. The increase is due to the inclusion of Enbridge Offshore Pipelines, which was acquired on December 31, 2004.

- 8 -

The Alliance Pipeline (US) earnings variance primarily reflects the impact of the stronger Canadian dollar in 2005.

Enbridge Offshore Pipelines was acquired on December 31, 2004. Hurricanes Katrina and Rita have negatively affected transmission volumes and the results of this business. The quarterly result includes property insurance deductibles as well as lost revenue on various systems prior to the commencement of contingent business interruption insurance coverage. The combined effect of the property damage deductibles and the estimated lost revenue reduced expected third quarter earnings by approximately $10 million.

Vector Pipeline earnings reflect the positive effect of continued growth in short haul firm transportation volumes offset by the negative impact of the stronger Canadian dollar in 2005.

Earnings are $9.9 million for the third quarter of 2005, compared with $12.3 million for the same period of 2004. Third quarter earnings in 2005 reflect the negative impacts of Hurricanes Katrina and Rita on Enbridge Offshore Pipelines and the impact of the stronger Canadian dollar on Alliance Pipeline (US) and Vector Pipeline.

Sponsored Investments
Earnings

Three months ended

Nine months ended

(millions of Canadian dollars)

September 30,

2005

2004

2005

2004

Enbridge Income Fund (EIF)

9.1

6.9

25.8

21.9

Enbridge Energy Partners (EEP)

2.3

5.9

13.9

20.0

Dilution Gains (EEP)

—

6.7

4.6

7.6

11.4

19.5

44.3

49.5

Earnings for the nine months ended September 30, 2005 are $44.3 million compared with $49.5 million in the same period of 2004. The variance reflects higher earnings from EIF offset by lower earnings from EEP.

The 2005 results from EIF include higher preferred unit distributions, as well as higher incentive income, consistent with EIF’s cash distribution increases in 2004. EIF’s operating results benefited from enhanced performance at both Alliance Canada and the Saskatchewan System.

EEP’s 2005 results reflect a number of factors including positive contributions from natural gas systems offset by lower Lakehead System volumes, a stronger Canadian dollar, a lower ownership interest and $5.9 million, net to Enbridge, of unrealized mark-to-market losses on derivative financial instruments which do not qualify for hedge accounting treatment. While Enbridge believes the hedging strategies are sound economic hedging techniques, they do not qualify for hedge accounting and must be accounted for on a mark-to-market basis through earnings.

EEP issued additional partnership units in 2005 and 2004 and, as Enbridge did not fully participate in these offerings, dilution gains resulted.

For the three months ended September 30, 2005, earnings are $11.4 million compared with $19.5 million for the same period in 2004, reflecting lower earnings in EEP offset by higher earnings from EIF, similar to the nine-month period.

- 9 -

Gas Distribution and Services
Earnings


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004
Enbridge Gas Distribution¹		(32.9	)		(22.7	)		55.4			121.2
Noverco¹		1.9			(0.1	)		21.7			28.5
CustomerWorks/ECS		6.6			3.4			18.9			12.6
Other Gas Distribution Operations¹		(1.0	)		1.1			4.9			8.0
Enbridge Gas New Brunswick		1.8			1.1			3.8			2.8
Gas Services		(0.8	)		0.8			(0.9	)		(0.2	)
Aux Sable		2.4			3.9			6.2			3.4
AltaGas Income Trust (investment sold in 2004)		—			0.8			—			21.1
Gain on sale of AltaGas Income Trust Units		—			97.8			—			97.8
Other		1.2			—			(0.1	)		1.3

		(20.8	)		86.1			109.9			296.5


¹		Earnings for 2005 are on a calendar year basis for the three and nine months ended September 30, 2005; whereas earnings for 2004 reflect earnings on a quarter lag basis for the three and nine months ended June 30, 2004. Effective December 31, 2004, EGD changed its fiscal year-end for financial reporting purposes from September 30 to December 31. Accordingly, the 2004 earnings from EGD, Noverco and Other Gas Distribution Operations are not comparable to earnings for 2005.

Earnings are $109.9 million for the nine months ended September 30, 2005 compared with $296.5 million for the nine months ended September 30, 2004. The earnings variance reflects the $97.8 million gain on the sale of the Company’s investment in AltaGas Income Trust during 2004, and the absence of earnings from this investment in 2005, as well as the change from quarter lag consolidation to calendar year consolidation for EGD, Noverco and Other Gas Distribution Operations. Reconciliations are provided below.

Earnings for the three months ended September 30, 2005 reflect the same factors as for the nine month period.


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004
Enbridge Gas Distribution — as reported		(32.9	)		(22.7	)		55.4			121.2
Significant non-operating factors and variances:
quarter lag earnings¹		—			22.7			—			(121.2	)
calendar basis earnings²		—			(36.1	)		—			73.6
warmer/(colder) than normal weather		0.2			(1.1	)		(1.5	)		(21.3	)
elimination of seasonal distribution rates		—			8.3			—			—

		(32.7	)		(28.9	)		53.9			52.3


¹		These earnings are for the three and nine months ended June 30, 2004 and were included in Enbridge’s consolidated earnings for the period ended September 30, 2004.

²		These earnings are for the three and nine months ended September 30, 2004 and were included in Enbridge’s consolidated earnings for the year ended December 31, 2004.

- 10 -

in 2005, this shifts a portion of earnings from the winter months to the summer months. The seasonal distribution rate variance, noted in the table above, is the effect of applying the uniform rate to 2004 results and volumes.

The third quarter variance at EGD reflects the timing of various expenses as compared to the forecast cost of service that is included in revenues, and is a reversal of the trend identified in the prior quarter.


	Three months ended					Nine months ended
(millions of Canadian dollars)	September 30,					September 30,
	2005		2004			2005			2004
Noverco — as reported		1.9		(0.1	)		21.7			28.5
Significant non-operating factors and variances:
quarter lag earnings¹		—		0.1			—			(28.5	)
calendar basis earnings²		—		(3.7	)		—			11.2
dilution gain in Noverco (Gaz Metro unit issuance)		—		—			(7.3	)		—

		1.9		(3.7	)		14.4			11.2


¹		These earnings are for the three and nine months ended June 30, 2004 and were included in Enbridge’s consolidated earnings for the period ended September 30, 2004.

²		These earnings are for the three and nine months ended September 30, 2004 and were included in Enbridge’s consolidated earnings for the year ended December 31, 2004.


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005		2004
Other Gas Distribution Operations — as reported		(1.0	)		1.1			4.9		8.0
Significant non-operating factors and variances:
quarter lag earnings¹		—			(1.1	)		—		(8.0	)
calendar basis earnings²		—			(1.3	)		—		4.8

		(1.0	)		(1.3	)		4.9		4.8


¹		These earnings are for the three and nine months ended June 30, 2004 and were included in Enbridge’s consolidated earnings for the period ended September 30, 2004.

²		These earnings are for the three and nine months ended September 30, 2004 and were included in Enbridge’s consolidated earnings for the year ended December 31, 2004.

- 11 -

International
Earnings


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004
CLH		14.2			10.9			39.8			35.4
OCENSA/CITCol		8.2			7.9			24.4			23.8
Other		(1.4	)		(2.7	)		(4.6	)		(5.6	)

		21.0			16.1			59.6			53.6

Earnings for the nine months ended September 30, 2005 are $59.6 million, an increase of $6.0 million from the same period in 2004. The increase is attributable to increased earnings from CLH as a result of increased volumes and higher average tariffs.

Increased earnings for the three months ended September 30, 2005 result from higher average tariffs and lower operating costs in CLH.

Corporate
Costs


	Three months ended						Nine months ended
(millions of Canadian dollars)	September 30,						September 30,
	2005			2004			2005			2004
Corporate		(15.3	)		(15.9	)		(46.9	)		(66.2	)

Corporate costs total $46.9 million for nine months ended September 30, 2005, a decrease of $19.3 million from the same period in 2004. The decrease is primarily the result of lower interest expense in 2005 and higher business development activity in 2004. The lower interest expense is a function of lower interest rates and lower average debt balances, including the December 2004 redemption of preferred securities with the proceeds from the AltaGas disposition.

LIQUIDITY AND CAPITAL RESOURCES

The Company expects to generate sufficient cash from operations to fund budgeted investing activity and common share dividends throughout the remainder of 2005. Additional liquidity, if necessary, is available under committed credit facilities or through access to the capital markets.

Consolidated cash flows for 2005 reflect cash flows from EGD, Noverco and Other Gas Distribution Operations on a calendar year basis for the three and nine months ended September 30, 2005, whereas cash flows for 2004 reflect cash flows from EGD, Noverco and Other Gas Distribution Operations for the three and nine months ended June 30, 2004. Effective December 31, 2004, EGD changed its fiscal year-end for financial reporting purposes from September 30 to December 31. Accordingly, the 2004 cash flows from EGD, Noverco and Other Gas Distribution Operations are not comparable to cash flows for 2005.

Enbridge started consolidating the accounts of EIF prospectively on January 1, 2005 and as such, the 2004 balances are not comparable.

- 12 -

Operating Activities

Cash from operations for the nine months ended September 30, 2005 is $922.3 million and reflects a decrease of $387.9 million from the same period in the prior year. The decrease is primarily due to changes in operating assets and liabilities, which decreased $507.7 million from the nine months ended September 30, 2004 primarily due to changes in working capital at EGD, which fluctuates seasonally. Before changes in operating assets and liabilities, cash from operations increased $119.8 million. This increase is primarily due to a special dividend of $70.6 million from Noverco, received during the third quarter of 2005.

For the three months ended September 30, 2005, cash used in operating activities was $98.9 million, compared to a source of cash of $418.2 million for the same period in 2004. The decrease results mainly from changes in operating assets and liabilities in EGD, partially offset by the special dividend from Noverco. The three and nine month periods are not comparable with 2004 due to the elimination of the quarter lag basis of accounting.

Investing Activities

Cash used for investing activities during the nine months ended September 30, 2005 is $492.0 million and $171.7 million for the three months ended September 30, 2005 compared to $36.7 million and a source of $154.2 million for the nine and three months ended September 30, 2004, respectively. The increases in cash used reflect the acquisitions of U.S. Oil and the remaining 20% of Garden Banks in the first quarter of 2005, the acquisition of the remaining 10% of the Spearhead Pipeline during the second quarter of 2005 and the acquisition of an additional interest in Neptune Pipeline Company in the third quarter of 2005. Also, in the first quarter of 2005, the Company paid a deferred acquisition cost that was contingent on CLH meeting certain target volumes. In the third quarter of 2004, the Company sold its investment in AltaGas Income Trust for cash proceeds of $251.4 million.

Financing Activities

The Company’s debt to capitalization ratio decreased to 63.6% from 65.1% on December 31, 2004, as the Company continues to repay debt and retained earnings continues to increase.

Financing activities during the nine months ended September 30, 2005 resulted in a use of cash of $375.4 million compared to $1,207.0 million in the nine months ended September 30, 2004. The Company used the proceeds of long-term debt issuances to repay short-term debt during the first quarter of 2005. This reduction in short-term debt was partially offset by third quarter short-term borrowings to fund EGD’s gas in storage. In 2004, the proceeds from the sale of the Company’s investment in AltaGas Income Trust were used to repay short-term debt.

During the three months ended September 30, 2005, financing activities resulted in a source of $294.6 million compared with a use of $506.2 million in the same period in 2004. The difference is due to seasonal changes in short-term borrowings in EGD which are not comparable year over year due to the elimination of the quarter lag basis of consolidation.

CHANGE IN ACCOUNTING POLICIES

Consolidation of Variable Interest Entities

Effective January 1, 2005 the Company adopted the new CICA accounting guideline for Consolidation of Variable Interest Entities. This new guideline requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity.

The Company has a 41.9% equity interest in Enbridge Income Fund (EIF), as well as a preferred unit investment that has no voting rights and a 30-year maturity. The preferred units earn a return that is equivalent to the per unit cash distributions earned by equity unit holders and are classified as a liability in EIF’s financial statements.

- 13 -

The Company is the primary beneficiary of EIF through a combination of the 41.9% equity interest and the preferred unit interest. The adoption of this guideline results in the inclusion of 100% of EIF’s financial statement balances in the Company’s financial statements but does not affect earnings.

Hedges, Financial Instruments — Recognition and Measurement and Comprehensive Income

New accounting standards will be in effect for fiscal years beginning on or after October 1, 2006 for hedge accounting, recognition and measurement of financial instruments and disclosure of comprehensive income. The Company is currently investigating the impact of these new standards.

RECLASSIFICATION

The Company has reclassified the revenue and cost of sales attributable to its marketing business to reflect the gross amounts. Previously, the Company had recorded these balances on a net basis. This business started primarily as a marketing agent for both the Government of Alberta and for one of the previous owners of the business. In recent years, the business has expanded to full service crude oil and natural gas liquids marketing. With a growing demand for these services and recent increases in the value of crude oil, the marketing side of the business has grown substantially. The reclassification better reflects the economics of the marketing business and prior period amounts have also been restated to reflect this change. There is no impact to earnings, retained earnings or earnings per share.

SELECTED QUARTERLY FINANCIAL INFORMATION¹


(millions of Canadian dollars,
except per share amounts)	2005						2004								2003
	Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4

Revenue		1,657.1		1,572.4		2,555.8		2,319.5		1,615.6		2,158.8		1,709.8		1,091.9
Earnings applicable to common shareholders		67.8		93.6		220.6		104.8		179.7		248.4		112.4		27.3
Earnings per common share		0.20		0.27		0.66		0.32		0.54		0.74		0.34		0.08
Diluted earnings per common share		0.20		0.27		0.65		0.32		0.54		0.73		0.34		0.08
Dividends per common share		0.2500		0.2500		0.2500		0.22875		0.22875		0.22875		0.22875		0.2075


¹		Quarterly Financial Information has been prepared in accordance with Canadian Generally Accepted Accounting Principles.

Revenue fluctuates primarily due to the seasonality of EGD. Prior to October 1, 2004, this business had a September 30 year-end, which resulted in consolidation by the Company on a quarter lag basis. Peak revenues were recorded in the Company’s second quarter, which represented EGD’s winter months. EGD has changed to a December 31 year-end and, as a result, the Company’s consolidated fourth quarter results for 2004 included the results of EGD for the six months ended December 31, 2004. EGD’s winter months are now consolidated in the Company’s first quarter earnings.

Effective October 1, 2004, EGD’s seasonal rates have been replaced with a uniform annual rate. This change results in lower earnings in the winter months, offset by higher earnings in the summer months, causing a shift in earnings between quarters but there is no earnings impact on a 12 consecutive month basis.

- 14 -

Significant items which impact the quarterly earnings are as follows:

	•		Fourth quarter earnings in 2003 include an $11.1 million dilution gain on an EEP unit issuance, and a $6.0 million dilution gain related to Noverco. Offsetting the gain is a $26.0 million write-down of a regulatory receivable and a $4.6 million regulatory decision on outsourcing, both in the Company’s gas distribution business.

	•		First quarter earnings in 2004 reflect a $47.6 million charge to earnings resulting from an increase in the Ontario tax rate and corresponding revaluation of future income taxes, as well as unbilled revenue of $35.0 million consistent with a change in the estimation process in 2004, both within EGD.

	•		Second quarter earnings in 2004 reflect the $9.4 million partial reversal of the $35.0 million of unbilled revenue recorded in the first quarter of 2004 and a dilution gain of $8.0 million related to AltaGas.

	•		Third quarter earnings in 2004 include a $97.8 million gain on the sale of the Company’s investment in AltaGas and the remaining reversal of $25.6 million related to unbilled revenue.

	•		Fourth quarter earnings in 2004 include the additional “fifth quarter” for EGD and other gas distribution businesses that account for an increase of $57.2 million. This was partially offset by an impairment loss of $8.2 million on the Calmar gas plant.

	•		First quarter earnings in 2005 include dilution gains in EEP and within Noverco totaling $11.9 million.

	•		Third quarter earnings in 2005 were negatively impacted by Hurricanes Katrina and Rita and by non-cash losses on the fair value of derivatives in EEP.

OUTSTANDING SHARE DATA


	Number of Shares
Common Shares – issued and outstanding (voting equity shares)		348,623,752

Preference Shares, Series A (non-voting equity shares)		5,000,000
Total issued and outstanding stock options (6,744,698 vested)		11,578,848

Outstanding share data information is provided as at October 24, 2005.

The Company has a Shareholder Rights plan designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Rights issued under the plan become exercisable when a person, and any related parties, acquires or announces its intention to acquire 20% or more of the Company’s outstanding common shares without complying with certain provisions set out in the plan or without approval of the Board of Directors of the Company. Should such an acquisition or announcement occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase common shares of the Company at a 50% discount to the market price at that time.

Additional information relating to Enbridge is available on www.sedar.com.

- 15 -

ENBRIDGE INC.
HIGHLIGHTS¹


(unaudited; millions of Canadian dollars	Three months ended						Nine months ended
except per share amounts)	September 30,						September 30,
	2005			2004			2005			2004
FINANCIAL
Earnings Applicable to Common Shareholders
Liquids Pipelines		61.6			61.6			168.2			167.9
Gas Pipelines		9.9			12.3			46.9			39.2
Sponsored Investments		11.4			19.5			44.3			49.5
Gas Distribution and Services		(20.8	)		86.1			109.9			296.5
International		21.0			16.1			59.6			53.6
Corporate		(15.3	)		(15.9	)		(46.9	)		(66.2	)

		67.8			179.7			382.0			540.5

Cash Provided By Operating Activities
Earnings plus charges/(credits) not affecting cash		251.3			188.4			916.1			796.3
Changes in operating assets and liabilities		(350.2	)		229.8			6.2			513.9

		(98.9	)		418.2			922.3			1,310.2

Common Share Dividends		86.9			79.0			260.7			236.6

Earnings per Common Share		0.20			0.54			1.13			1.62

Diluted Earnings per Common Share		0.20			0.54			1.12			1.61

Dividends per Common Share		0.2500			0.2288			0.7500			0.6863

Weighted Average Common Shares Outstanding (millions)								337.2			334.2

Diluted Weighted Average Common Shares Outstanding (millions)								340.7			337.1


OPERATING
Liquids Pipelines²
Deliveries (thousands of barrels per day)		1,908			2,110			1,979			2,125
Barrel miles (billions)		168			189			513			565
Average haul (miles)		959			975			949			971
Gas Distribution and Services³
Volumes (billion cubic feet)		45			76			309			398
Number of active customers (thousands)		1,782			1,737			1,782			1,737
Degree day deficiency⁴
Actual		23			723			2,476			3,733
Forecast based on normal weather		60			714			2,500			3,521


1.		Financial and operating highlights of Gas Distribution and Services for 2004 reflect the results of Enbridge Gas Distribution (EGD) and other gas distribution operations on a one-quarter lag basis for the three and nine months ended June 30, 2004. For 2005, as a result of EGD’s change in fiscal year end from September 30 to December 31, financial and operating highlights reflect the results of EGD and other gas distribution operations for the three and nine months ended September 30, 2005.

2.		Liquids Pipelines operating highlights include the statistics of the 11.2% owned Lakehead System and other wholly-owned liquid pipeline operations.

3.		Gas Distribution and Services volumes and the number of active customers are derived from the aggregate system supply and direct purchase gas supply arrangements.

4.		Degree-day deficiency is a measure of coldness. It is calculated by accumulating for each day in the period the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Toronto area.

- 16 -

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars, except per share amounts)	2005			2004			2005			2004

Revenues
Commodity sales		1,142.1			1,202.1			4,108.0			4,070.7
Transportation		430.7			396.6			1,439.3			1,258.0
Energy services		84.3			16.8			238.0			155.5

		1,657.1			1,615.5			5,785.3			5,484.2

Expenses
Commodity costs		1,076.9			1,114.0			3,789.9			3,634.2
Operating and administrative		267.4			217.6			782.0			657.4
Depreciation		141.2			115.1			427.5			340.6

		1,485.5			1,446.7			4,999.4			4,632.2

Operating Income		171.6			168.8			785.9			852.0
Investment and Other Income		21.1			51.7			143.9			223.1
Gain on Sale of Investment in AltaGas Income Trust Units		—			121.5			—			121.5
Interest Expense		(133.0	)		(119.7	)		(402.4	)		(366.9	)

		59.7			222.3			527.4			829.7
Income Taxes		9.8			(40.8	)		(140.3	)		(284.0	)

Earnings		69.5			181.5			387.1			545.7
Preferred Share Dividends		(1.7	)		(1.8	)		(5.1	)		(5.2	)

Earnings Applicable to Common Shareholders		67.8			179.7			382.0			540.5


Earnings Per Common Share		0.20			0.54			1.13			1.62


Diluted Earnings Per Common Share		0.20			0.54			1.12			1.61

See accompanying notes to the unaudited consolidated financial statements.

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS


	Nine months ended
	September 30,
(unaudited; millions of Canadian dollars)	2005			2004

Retained Earnings at Beginning of Period		1,840.9			1,511.4
Earnings Applicable to Common Shareholders		382.0			540.5
Common Share Dividends		(260.7	)		(236.6	)
Dividends Paid to Reciprocal Shareholder		8.1			—
Dividend Reclassification Adjustment (Note 3)		51.2			—

Retained Earnings at End of Period		2,021.5			1,815.3

See accompanying notes to the unaudited consolidated financial statements.

-1-

ENBRIDGE INC.
CONSOLIDATED STATEMENT OF CASH FLOWS


	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars)	2005			2004			2005			2004

Cash Provided By Operating Activities Earnings		69.5			181.5			387.1			545.7
Charges/(credits) not affecting cash
Depreciation		141.2			115.1			427.5			340.6
Equity earnings less than/(in excess of) cash distributions		82.8			1.5			61.3			(53.6	)
Gain on reduction of ownership interest		—			(17.3	)		(15.6	)		(29.6	)
Gain on sale of investment in AltaGas Income Trust Units		—			(121.5	)		—			(121.5	)
Future income taxes		(44.5	)		(7.3	)		40.5			74.7
Other		2.3			36.4			15.3			40.0
Changes in operating assets and liabilities		(350.2	)		229.8			6.2			513.9

		(98.9	)		418.2			922.3			1,310.2

Investing Activities
Acquisitions		(28.3	)		—			(86.4	)		(17.4	)
Changes in long-term investments		(0.3	)		(0.7	)		(62.1	)		(16.9	)
Additions to property, plant and equipment		(141.5	)		(97.4	)		(341.0	)		(251.6	)
Sale of investment in AltaGas Income Trust Units		—			251.4			—			251.4
Changes in construction payable		(2.1	)		0.9			(2.4	)		(2.2	)
Changes in long-term notes receivable		0.5			—			(0.1	)		—

		(171.7	)		154.2			(492.0	)		(36.7	)

Financing Activities
Net change in short-term borrowings and short-term debt		377.2			(434.4	)		(332.6	)		(1,017.1	)
Non-recourse short-term debt of joint ventures		(6.5	)		—			5.4			(5.0	)
Long-term debt issues		—			—			620.1			300.0
Long-term debt repayments		—			—			(396.9	)		(250.0	)
Non-recourse long-term debt repaid by joint ventures		(2.4	)		—			(54.8	)		(24.5	)
Non-recourse long-term debt issued by joint ventures		—			—			6.8			—
Non-controlling interests		7.4			1.6			(4.5	)		(0.3	)
Common shares issued		7.5			7.4			46.9			31.7
Preferred share dividends		(1.7	)		(1.8	)		(5.1	)		(5.2	)
Common share dividends		(86.9	)		(79.0	)		(260.7	)		(236.6	)

		294.6			(506.2	)		(375.4	)		(1,207.0	)

Increase in Cash		24.0			66.2			54.9			66.5
Cash at Beginning of Period		136.4			104.4			105.5			104.1

Cash at End of Period		160.4			170.6			160.4			170.6

See accompanying notes to the unaudited consolidated financial statements.

-2-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	September 30,			December 31,
(unaudited; millions of Canadian dollars)	2005			2004

Assets
Current Assets
Cash		160.4			105.5
Accounts receivable and other		1,295.4			1,451.9
Inventory		1,042.5			791.6

		2,498.3			2,349.0
Property, Plant and Equipment, net		10,265.2			9,066.5
Long-Term Investments		1,809.0			2,278.3
Receivable from Affiliate		174.0			171.7
Deferred Amounts and Other Assets		856.7			729.2
Goodwill		357.7			31.5
Intangible Assets		238.9			133.9
Future Income Taxes		147.0			145.0

		16,346.8			14,905.1


Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings		742.8			650.6
Accounts payable and other		1,408.7			1,275.9
Interest payable		71.7			83.8
Current maturities and short-term debt		541.2			703.9
Current portion of non-recourse long-term debt		76.1			30.2

		2,840.5			2,744.4
Long-Term Debt		5,998.1			6,053.3
Non-Recourse Long-Term Debt		1,634.9			665.2
Other Long-Term Liabilities		93.6			151.8
Future Income Taxes		944.8			797.3
Non-Controlling Interests		672.3			514.9

		12,184.2			10,926.9
Shareholders’ Equity
Share capital
Preferred shares		125.0			125.0
Common shares		2,329.3			2,282.4
Contributed surplus		8.4			5.4
Retained earnings		2,021.5			1,840.9
Foreign currency translation adjustment		(185.9	)		(139.8	)
Reciprocal shareholding		(135.7	)		(135.7	)

		4,162.6			3,978.2

		16,346.8			14,905.1

See accompanying notes to the unaudited consolidated financial statements.

-3-

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and should be read in conjunction with the consolidated financial statements and notes thereto included in Enbridge Inc.’s 2004 Annual Report. These accounting principles are different in some respects from United States generally accepted accounting principles and the significant differences that impact the Company’s financial statements are described in Note 7. These interim financial statements follow the same significant accounting policies and methods of application as those included in the 2004 Annual Report except as described in Note 1.

Earnings for interim periods may not be indicative of results for the fiscal year due to weather and other factors. Certain reclassifications have been made to the prior period financial statements to conform to the current year’s presentation.

1. ACCOUNTING CHANGES

Consolidation of Variable Interest Entities

Effective January 1, 2005 the Company adopted, without restatement of prior periods, the new CICA accounting guideline for Consolidation of Variable Interest Entities (AcG 15). This new standard requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity.

The Company has a 41.9% equity interest in Enbridge Income Fund (EIF), as well as a preferred unit investment that has no voting rights, a stated par value and a 30-year maturity. The preferred units earn a return that is equivalent to the cash distributions per unit to the equity unit holders and are classified as a liability in EIF’s financial statements.

The Company is the primary beneficiary of EIF through a combination of the 41.9% equity interest and the preferred unit interest.

-4-

Consolidating EIF had the following impact on the financial statements:


Statement of Financial Position	September 30,
(millions of Canadian dollars)	2005

Assets
Cash		33.5
Accounts receivable and other		25.7
Property, plant and equipment, net		1,227.5
Deferred amounts and other assets		38.3
Goodwill		308.1
Intangible assets		104.4

		1,737.5
Less: Liabilities
Accounts payable and other		37.8
Current portion of non-recourse long-term debt		35.3
Non-recourse long-term debt		1,019.0
Other long-term liabilities		7.0
Future income taxes		89.1
Non-controlling interests		168.7

		1,356.9
		380.6
Elimination of investment in EIF		(380.6	)

Net financial position impact	*nil*


Statement of Earnings	Three months ended			Nine months ended
(millions of Canadian dollars)	September 30, 2005			September 30, 2005

Transportation revenue		63.3			185.3
Less: Expenses
Operating and administrative		15.3			43.1
Depreciation		17.8			53.2
Investment and other income		2.8			6.8
Interest expense		15.2			46.5
Income taxes		(0.2	)		(0.4	)

		50.9			149.2
		12.4			36.1
Elimination of EIF investment income		(12.4	)		(36.1	)

Net earnings impact	*nil*			*nil*


Statement of Cash Flows	Three months ended			Nine months ended
(millions of Canadian dollars)	September 30, 2005			September 30, 2005

Operating activities		31.9			62.5
Investing activities		(5.8	)		(8.9	)
Financing activities		(4.7	)		(34.9	)

Net cash flow impact		21.4			18.7

- 5 -

Revenue and Cost of Sales

The Company has reclassified the revenues and cost of sales attributable to its marketing business to reflect the gross amounts. Previously, the Company had reported these balances on a net basis. The reclassification reflects changes in the types of transactions undertaken by the business, and the growth of the business. Prior period comparative amounts have been restated to reflect this change. The change increases Commodity Sales by $1,316.4 million for the nine months ended September 30, 2005 (2004 — $913.0 million) and by $567.6 million for the three months ended September 30, 2005 (2004 — $334.8 million), increases Commodity Costs by $1,302.2 million for the nine months ended September 30, 2005 (2004 — $907.7 million) and by $560.6 million for the three months ended September 30, 2005 (2004 — $333.6 million) and reduces Energy Services revenues by $14.2 million for the nine months ended September 30, 2005 (2004 — $5.3 million) and by $6.9 million for the three months ended September 30, 2005 (2004 — $1.2 million). The reclassification has no impact on operating income, earnings, earnings per share, or retained earnings.

Preferred Securities

Effective December 31, 2004, the Company early adopted amendments to the CICA Standard on the disclosure and presentation of financial instruments. The amendments require the Company’s preferred securities to be classified wholly as debt. The amendments were adopted retroactively and have resulted in the restatement of certain comparative amounts. For the three and nine months ended September 30, 2004, interest expense increased $10.4 million and $31.1 million, income taxes decreased $3.4 million and $10.2 million and preferred security distributions of $7.0 million and $20.9 million were eliminated.

2. SEGMENTED INFORMATION

Three months ended September 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

222.8

83.9

63.3

1,284.3

2.8

—

1,657.1

Commodity costs

—

(1,076.9

)

—

(1,076.9

)

Operating and administrative

(76.8

)

(25.7

)

(15.4

)

(139.5

)

(3.6

)

(6.4

)

(267.4

)

Depreciation

(37.0

)

(21.9

)

(17.8

)

(62.7

)

(0.2

)

(1.6

)

(141.2

)

Operating income

109.0

36.3

30.1

5.2

(1.0

)

(8.0

)

171.6

Investment and other income

0.8

0.3

0.4

(4.4

)

23.3

0.7

21.1

Interest and preferred equity charges

(24.5

)

(19.9

)

(15.2

)

(44.6

)

—

(30.5

)

(134.7

)

Income taxes

(23.7

)

(6.8

)

(3.9

)

23.0

(1.3

)

22.5

9.8

Earnings applicable to common shareholders

61.6

9.9

11.4

(20.8

)

21.0

(15.3

)

67.8

-6-

Three months ended September 30, 2004


										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of Canadian dollars)	Pipelines			Pipelines			Investments			and Services¹			International			Corporate			Consolidated

Revenues		221.6			66.7			—			1,320.1			7.1			—			1,615.5
Commodity costs		—			—			—			(1,114.0	)		—			—			(1,114.0	)
Operating and administrative		(70.7	)		(13.5	)		—			(114.6	)		(9.8	)		(9.0	)		(217.6	)
Depreciation		(36.0	)		(16.5	)		—			(61.3	)		(0.4	)		(0.9	)		(115.1	)

Operating income		114.9			36.7			—			30.2			(3.1	)		(9.9	)		168.8
Investment and other income		0.7			0.1			36.0			(1.9	)		19.6			(2.8	)		51.7
Gain on sale of investment		—			—			—			121.5			—			—			121.5
Interest and preferred equity charges		(25.9	)		(16.4	)		—			(40.6	)		—			(38.6	)		(121.5	)
Income taxes		(28.1	)		(8.1	)		(16.5	)		(23.1	)		(0.4	)		35.4			(40.8	)

Earnings applicable to common shareholders		61.6			12.3			19.5			86.1			16.1			(15.9	)		179.7

Nine months ended September 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

648.7

278.7

185.3

4,664.3

8.3

—

5,785.3

Commodity costs

—

(3,789.9

)

—

(3,789.9

)

Operating and administrative

(228.0

)

(70.0

)

(43.5

)

(413.5

)

(11.7

)

(15.3

)

(782.0

)

Depreciation

(110.7

)

(70.0

)

(53.2

)

(188.3

)

(0.8

)

(4.5

)

(427.5

)

Operating income

310.0

138.7

88.6

272.6

(4.2

)

(19.8

)

785.9

Investment and other income

(0.4

)

1.6

31.2

20.8

66.2

24.5

143.9

Interest and preferred equity charges

(73.0

)

(62.6

)

(46.5

)

(131.9

)

—

(93.5

)

(407.5

)

Income taxes

(68.4

)

(30.8

)

(29.0

)

(51.6

)

(2.4

)

41.9

(140.3

)

Earnings applicable to common shareholders

168.2

46.9

44.3

109.9

59.6

(46.9

)

382.0

Nine months ended September 30, 2004


										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of Canadian dollars)	Pipelines			Pipelines			Investments			and Services¹			International			Corporate		Consolidated

Revenues		646.5			206.4			—			4,608.1			23.2		—			5,484.2
Commodity costs		—			—			—			(3,634.2	)		—		—			(3,634.2	)
Operating and administrative		(219.9	)		(41.9	)		—			(347.4	)		(28.5	)	(19.7	)		(657.4	)
Depreciation		(107.7	)		(50.4	)		—			(178.8	)		(1.3	)	(2.4	)		(340.6	)

Operating income		318.9			114.1			—			447.7			(6.6	)	(22.1	)		852.0
Investment and other income		1.7			0.5			86.8			57.4			61.9		14.8			223.1
Gain on sale of investment		—			—			—			121.5			—		—			121.5
Interest and preferred equity charges		(76.3	)		(50.4	)		—			(127.3	)		(0.1	)	(118.0	)		(372.1	)
Income taxes		(76.4	)		(25.0	)		(37.3	)		(202.8	)		(1.6	)	59.1			(284.0	)

Earnings applicable to common shareholders		167.9			39.2			49.5			296.5			53.6		(66.2	)		540.5

Gas Distribution and Services results for 2004 were consolidated on a one-quarter-lag basis and therefore reflect the three and nine month periods ended June 30, 2004. Starting at the end of 2004, EGD changed its fiscal year end from September 30 to December 31. Therefore, the quarter lag basis of consolidation was eliminated. Gas Distribution and Services results for 2005 reflect the three and nine month periods ended September 30, 2005.

-7-

3. ACQUISITIONS AND LONG-TERM INVESTMENTS

U.S. Oil

On January 6, 2005, the Company acquired the industrial gas sales business of U.S. Oil Co. Inc. The purchase price included $30.0 million for goodwill and intangibles.

Garden Banks

On March 22, 2005, the Company acquired the remaining 20% of Garden Banks Gas Pipeline, a business included in Enbridge Offshore Pipelines.

Spearhead Pipeline

On June 1, 2005, the Company acquired the remaining 10% of CCPS Transportation L.L.C., owner of the Spearhead Pipeline (formerly known as the Cushing to Chicago Pipeline System).

Neptune

On September 30, 2005, the Company acquired an additional 24.33% interest in Neptune Pipeline Company, L.L.C. (Neptune), a business included in Enbridge Offshore Pipelines. The acquisition increases the Company’s interest in Neptune to 74.33%.

Noverco

During the nine month period ended September 30, 2005, a special dividend was declared by Noverco, an equity investee. The equity investment balance was reduced $70.6 million to reflect the impact of the special dividends on the accounts of the Company.

On June 30, 2005, the Company reclassified $51.2 million in dividends paid to Noverco. The reclassification increased equity investments and retained earnings by $51.2 million and represented the reciprocal portion of dividends paid to Noverco from September 1, 1997 to December 31, 2004. The reciprocal shareholding results in a portion of the dividends paid to Noverco effectively being dividends paid to the Company.

4. STOCK SPLIT

On May 5, 2005, shareholders approved a two-for-one split of the common shares of the Company. All references to earnings per common share, diluted earnings per common share, stock options and performance stock units have been retroactively restated to reflect the impact of the stock split.

5. STOCK-BASED COMPENSATION

During the nine months ended September 30, 2005, 1.5 million (2004 – 1.8 million) fixed stock options were issued at a weighted average exercise price of $31.68 (2004 — $25.72). The weighted average grant-date fair value of the fixed stock options granted during the nine months ended September 30, 2005 was $5.30 (2004 — $3.85) for each option granted³. Outstanding stock options expire over a period no later than June 16, 2015. The Company has applied the fair-value based method of accounting for stock options granted after January 1, 2003. Under this method, earnings include a compensation charge representing the fair value of options granted in years 2003 through 2005 amortized over the vesting period, with a corresponding increase to contributed surplus.

In addition, the Company granted 130,130 Performance Stock Units (PSUs) (2004 – 65,950) to the Company’s senior officers during the nine months ended September 30, 2005. The PSUs granted in 2005 mature January 1, 2008. Compensation costs for PSUs are accounted for over the three-year

- 8 -

period on a mark-to-market basis, whereby a liability and expense are recorded based upon the number of PSUs outstanding, the current market price of the Company’s stock, and the Company’s performance relative to the specified peer group.

If the Company had used the fair-value based method to account for fixed stock options and performance-based options granted in fiscal 2002, earnings and earnings per share would have been as follows:

Three months ended

Nine months ended

September 30,

(millions of Canadian dollars, except per share amounts)

2005

2004

2005

2004

Earnings applicable to common shareholders

As reported

67.8

179.7

382.0

540.5

Total stock-based compensation expense 1

(3.2

)

(2.1

)

(9.1

)

(6.1

)

Included as an expense in the statement of earnings ²

2.2

1.1

6.1

3.1

Pro forma earnings

66.8

178.7

379.0

537.5

Earnings per share

As reported

0.20

0.54

1.13

1.62

Pro forma

0.20

0.53

1.12

1.61

Diluted earnings per share

As reported

0.20

0.54

1.12

1.61

Pro forma

0.20

0.53

1.11

1.60

Total stock-based compensation expense if the fair-value based method to expense all outstanding stock options had been applied since January 1, 2002.

Stock-based compensation recognized as an expense in the statement of earnings for options and performance stock units granted in 2003 through 2005 as a result of the adoption of the fair-value based method on January 1, 2003.

The Black-Scholes model was used to calculate the fair-value of the fixed stock options. Significant assumptions include a risk-free interest rate of 4.4% (2004 — 4.8%), expected volatility of 16% (2004 — 15%), an expected life of 8 years (2004 — 8 years) and an expected dividend yield of 3.17% (2004 — 3.54%).

6. POST-EMPLOYMENT BENEFITS

Pension Plans

The Company has three pension plans, which provide either defined benefit or defined contribution pension benefits, or both, for employees of the Company. The Liquids Pipelines and Gas Distribution and Services pension plans provide non-contributory defined pension benefits and/or defined contribution benefits to Canadian employees of Enbridge. The Enbridge U.S. pension plan provides a non-contributory defined benefit pension plan to U.S. employees of Enbridge. The Company also provides post-employment benefits other than pensions (OPEB) for qualifying retired employees. Costs recognized in the period are presented below.

- 9 -

Net Pension and OPEB Costs Recognized


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2005			2004			2005			2004

Benefits earned during the period		8.0			7.3			24.2			22.0
Interest cost on projected benefit obligations		15.7			14.7			47.4			44.2
Expected return on plan assets		(18.9	)		(17.7	)		(56.7	)		(53.2	)
Amortization and deferral of unrecognized amounts		3.1			3.0			9.3			10.6
Amount charged to Enbridge Energy Partners L.P.		(2.4	)		(1.4	)		(7.3	)		(5.9	)
Amount charged to Enbridge Income Fund		—			(0.2	)		—			(0.6	)

Pension and OPEB costs recognized		5.5			5.7			16.9			17.1

The above reflects the pension and OPEB cost for all of the Company’s benefit plans on an accrual basis. However, in accordance with its ability to recover employee benefit costs on a pay-as-you-go basis for the regulated operations of Gas Distribution and Services, the Company records the cost of such benefits on a cash basis. Using the cash basis for the Gas Distribution and Services plans and the accrual method for other plans, the Company’s pension and OPEB costs are $13.6 million for the nine month period ended September 30, 2005 (2004 — $12.1 million) and $4.5 million for the three month period ended September 30, 2005 (2004 — $4.6 million).

7. UNITED STATES ACCOUNTING PRINCIPLES

These consolidated financial statements have been prepared in accordance with Canadian GAAP. The effects of significant differences between Canadian GAAP and U.S. GAAP for the Company are described below.

Earnings and Comprehensive Income


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars, except per share amounts)	2005			2004			2005			2004

Earnings under Canadian GAAP		67.8			179.7			382.0			540.5
U.S. GAAP earnings adjustments¹		—			—			(6.6	)		—
Tax effect of the above adjustments		—			—			2.6			—

Earnings under U.S. GAAP		67.8			179.7			378.0			540.5
Unrealized net gain/(loss) on cash flow hedges⁵		68.6			11.4			115.8			(15.5	)
Foreign currency translation adjustment⁵		(67.0	)		(12.0	)		(32.4	)		24.9

Comprehensive income		69.4			179.1			461.4			549.9

Earnings per common share		0.20			0.54			1.12			1.62

Diluted earnings per common share		0.20			0.54			1.11			1.61

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Financial Position

(millions of dollars)


	September 30, 2005					December 31, 2004
	Canada			United States		Canada			United States

Cash⁶		160.4			160.4		105.5			120.3
Accounts receivable and other^4,5,6		1,295.4			1,461.0		1,451.9			1,483.6
Property, plant and equipment, net⁶		10,265.2			10,265.2		9,066.5			10,334.1
Long-term investments⁶		1,809.0			1,809.0		2,278.3			1,898.1
Deferred amounts^2,6		856.7			1,575.6		729.2			1,699.2
Intangible assets⁶		238.9			238.9		133.9			242.2
Goodwill⁶		357.7			357.7		31.5			339.6
Accounts payable and other^1,4,5,6		1,408.7			1,448.9		1,275.9			1,375.8
Current maturities and short-term debt^5,6		541.2			537.2		703.9			715.2
Current portion of non-recourse debt⁶		76.1			76.1		30.2			71.7
Long-term debt^4,5,6		5,998.1			6,000.8		6,053.3			6,264.9
Non-recourse long-term debt⁶		1,634.9			1,634.9		665.2			1,503.5
Other long-term liabilities⁶		93.6			93.6		151.8			158.5
Future income taxes^2,4,5,6		944.8			1,708.9		652.3			1,638.9
Non-controlling interests⁶		672.3			672.3		514.9			689.9
Retained earnings		2,021.5			1,946.9		1,840.9			1,770.3
Contributed surplus¹		8.4			—		5.4			—
Additional paid-in capital¹		—			42.3		—			27.3
Foreign currency translation adjustment⁵		(185.9	)		—		(139.8	)		—
Accumulated other comprehensive loss⁵		—			63.7		—			(147.1	)

1. Stock-based Compensation

Effective January 1, 2003, the Company adopted FAS 123, Accounting for Stock-Based Compensation, on a prospective basis for U.S. GAAP, and elected to use the fair value-based method to measure compensation expense for all options issued after January 1, 2003. The adoption of the fair value method for U.S. GAAP eliminates all differences between Canadian and U.S. GAAP for options granted subsequent to the date of adoption. Disclosure differences in pro forma earnings between Canadian and U.S. GAAP will remain for those options granted prior to adoption, on January 1, 2002, of the Canadian accounting standard for stock-based compensation. Earnings differences will remain for performance- based options granted during 2002 when they vest.

Prior to the adoption of FAS 123, the Company accounted for stock-based compensation for U.S. GAAP in accordance with APB 25, Accounting for Stock Issued to Employees, which required the use of the intrinsic value-based method to measure compensation expense. Under U.S. GAAP 405,000 of the 2002 issuance of performance-based options vested during 2005, giving rise to a pre-tax compensation expense of $6.6 million (2004 — nil).

2. Future Income Taxes

Under U.S. GAAP, deferred income tax liabilities are recorded for rate-regulated operations, which follow the taxes payable method for ratemaking purposes. As these deferred income taxes are expected to be recoverable in future revenues, a corresponding regulatory asset is also recorded. These assets and liabilities are adjusted to reflect changes in enacted income tax rates. A deferred tax liability of $718.0 million (2004 - $688.3 million) is recorded for U.S. GAAP purposes and reflects the difference between the accounting basis and the tax basis of property, plant and equipment.
Regulated companies following the taxes payable method are not required to record this additional tax liability under Canadian GAAP. To recover the additional deferred income taxes recorded under U.S. GAAP through the ratemaking process, it would be necessary to record incremental revenue of $395.1 million (2004 — $378.8 million).

3. Accounting for Joint Ventures

U.S. GAAP requires the Company’s investments in joint ventures be accounted for using the equity method. However, under an accommodation of the U. S. Securities and Exchange Commission, accounting for joint ventures need not be reconciled from Canadian to U.S. GAAP. The different accounting treatment affects only display and classification and not earnings or shareholders’ equity.

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4. Financial Instruments

For U.S. GAAP purposes, FAS 133, Accounting for Derivative Instruments and Hedging Activities, requires that all derivatives be recorded on the balance sheet as either assets or liabilities at their fair value. Changes in the derivative’s fair value are recognized in current period earnings unless specific hedge accounting criteria are met.

The accounting for changes in the fair value of derivatives held for hedging purposes depends upon their intended use. For fair value hedges, the effective portion of changes in the fair value of derivative instruments is offset in income against the change in fair value, attributed to the risk being hedged, of the underlying hedged asset, liability or firm commitment. For cash flow hedges, the effective portion of changes in the fair value of derivative instruments is offset through other comprehensive income (or loss), until the variability in cash flows being hedged is recognized in earnings in future accounting periods.

5. Accumulated Other Comprehensive Loss

At September 30, 2005, Accumulated Other Comprehensive Loss of $63.7 million consists of an accumulated foreign currency translation balance of $161.5 million (2004 — $106.6 million) and net unrealized gains of $97.8 million (2004 — losses of $0.6 million). For U.S. GAAP purposes, the foreign currency translation adjustment balance is classified as a component of Accumulated Other Comprehensive Loss. The fair value of derivative financial instruments that qualify as cash flow hedges are also included in Accumulated Other Comprehensive Loss.

Of the total Accumulated Other Comprehensive Loss of $63.7 million, the Company estimates that approximately $93.9 million, representing unrecognized net gains on derivative activities at September 30, 2005, is expected to be reclassified into earnings during the next twelve months and primarily relates to natural gas supply management.

6. Consolidation of Variable Interest Entities

On December 24, 2003, the Financial Accounting Standards Board issued a revision to FASB Interpretation (FIN) 46, which replaces the interpretation released in January 2003.

FIN 46R requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest. The Company is the primary beneficiary of EIF through a combination of the 41.9% equity interest and the preferred unit interest. Effective January 1, 2005 the Company adopted without restatement of prior periods the new CICA accounting guideline for Consolidation of Variable Interest Entities (AcG 15). AcG 15 and FIN 46R do not create U.S. GAAP differences for the Company, therefore there is not a U.S. GAAP difference related to variable interest entities at September 30, 2005. The impact of FIN 46R included in the U.S. GAAP amounts for the three and nine months ended September 30, 2004 and at December 31, 2004 is outlined below:

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Statement of Financial Position	December 31,
(millions of Canadian dollars)	2004

Cash		14.8
Accounts receivable and other		22.7
Property, plant and equipment, net		1,267.8
Deferred amounts and other assets		42.0
Intangible assets		108.3
Goodwill		308.1

		1,763.7
Less: Liabilities
Accounts payable and other		22.7
Current portion of non-recourse long-term debt		41.5
Non recourse long-term debt		1,045.3
Other long-term liabilities		6.7
Future income taxes		92.1
Non-controlling interests		175.0

		1,383.3
		380.4
Elimination of investment in EIF		(380.4	)

Net financial position impact	*nil*


Statement of Earnings	Three months ended			Nine months ended
(millions of Canadian dollars)	September 30, 2004			September 30, 2004

Transportation revenue		58.4			179.9
Operating and administrative		(14.3	)		(45.6	)
Depreciation		(17.5	)		(52.9	)
Investment and other income		(1.1	)		(4.1	)
Interest expense		(14.9	)		(45.2	)
Income taxes		0.1			0.3

		10.7			32.4
Elimination of EIF investment income		(10.7	)		(32.4	)

Net earnings impact	*nil*			*nil*


Statement of Cash Flows	Three months ended			Nine months ended
(millions of Canadian dollars)	September 30, 2004			September 30, 2004

Operating activities		29.3			57.2
Investing activities		(5.2	)		(8.4	)
Financing activities		(0.9	)		(40.5	)

Net cashflow impact		23.2			8.3

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New Accounting Standards

In June 2005, the U.S. Emerging Issues Task Force, or EITF, reached a consensus on EITF issue 04- 5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights (EITF 04-5), addressing when a general partner, or general partners as a group, control and should therefore, consolidate a limited partnership. Under EITF 04-5, a sole general partner is presumed to control a limited partnership when certain conditions are met. As a result, for the first reporting period beginning after December 15, 2005, it is expected that the Company will be required to include the accounts of Enbridge Energy Partners, L.P. for U.S. GAAP purposes.

Supplemental Disclosure — Pro Forma Compensation Expense

U.S. GAAP requires that, where the fair value based method is not used to measure compensation expense, pro forma earnings and earnings per share, calculated as if the fair value based method had been used, must be disclosed. In Canada, these requirements apply to options granted on or after January 1, 2002 and therefore, the Company’s Canadian GAAP disclosure does not include any options granted prior to that date.


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of dollars except per share amounts)	2005			2004			2005			2004

Earnings under U.S. GAAP
As reported		67.8			179.7			378.0			540.5
Stock-based compensation expense		(2.8	)		(2.1	)		(11.1	)		(6.1	)
Included as an expense in the statements of earning		2.2			1.1			10.1			3.1

Pro forma		67.2			178.7			377.0			537.5
Earnings per common share
As reported		0.20			0.54			1.12			1.62
Stock-based compensation expense		—			0.01			—			0.02

Pro forma		0.20			0.53			1.12			1.60
Diluted earnings per common share
As reported		0.20			0.54			1.11			1.61
Stock-based compensation expense		—			0.01			—			0.02

Pro forma		0.20			0.53			1.11			1.59

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