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 July 28, 2005
Commission file number 0-21080

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)


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

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 AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

Page 1

TABLE OF CONTENTS


SIGNATURES

The following document is being submitted herewith:

•

Press Release dated July 28, 2005.

•

Interim Report to Shareholders for the six months ended June 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:	July 28, 2005	By:	/s/ “Alison T. Love”
			Alison T. Love
			Vice President & Corporate Secretary

Page 2

NEWS RELEASE

Enbridge reports first half earnings of $314.2 million

Highlights

	•		Adjusted operating earnings for the first half increase 10% to $300.6 million

	•		Adjusted operating earnings for the second quarter increase 15% to $95.6 million

	•		New five-year Incentive Tolling Settlement adds value for Enbridge and liquids shippers

	•		Gateway Condensate and Southern Access open seasons advance growth initiatives

	•		Neptune laterals project builds on recently acquired deepwater assets in the Gulf of Mexico

CALGARY, Alberta, July 28, 2005 – “This has been a very strong quarter with a 15% increase in adjusted operating earnings and significant progress on a number of important growth initiatives” said Patrick D. Daniel, President & Chief Executive Officer of Enbridge Inc. “Our earnings performance in the first six months of 2005 positions us well to meet our previously stated expectations for the year.”

Mr. Daniel concluded, “During the quarter we launched formal open seasons to confirm shipper support for the Gateway condensate project as well as the Southern Access expansion and extension. Enbridge is working hard on these projects and many others to address strong supply and demand fundamentals and meet the needs of our customers while ensuring we continue to deliver superior returns to our shareholders.”

On July 27, 2005, the Enbridge Board of Directors declared quarterly dividends of $0.25 per common share on a post-split basis and $0.34375 per Series A Preferred Share. Both dividends are payable on September 1, 2005 to shareholders of record on August 15, 2005. On May 5, 2005, the Company’s shareholders approved a stock split with a record date of May 20, 2005.

The Board of Directors of Enbridge announced today that Donald J. Taylor has rejoined the Board and that David A. Leslie has been appointed as a director. Mr. Taylor, the former Chair of the Board, did not stand for re-election as a director at the annual shareholders’ meeting in May 2005, having reached the normal age for retirement. The Board asked that Mr. Taylor re-join the Board for an additional two years, noting the valuable advice Mr. Taylor has provided to Enbridge. Mr. Leslie, a resident of Toronto, is a chartered accountant and the former Chairman and CEO of Ernst & Young LLP.

Earnings applicable to common shareholders are $314.2 million for the six months ended June 30, 2005, or $0.93 per share, compared with $360.8 million, or $1.08 per share, in 2004. The $46.6 million decrease in earnings is due to the previously announced change in the year-end of the gas distribution operations and the elimination of seasonal distribution rates at Enbridge Gas Distribution. These factors create a lack of comparability between periods, however a reconciliation is provided below. Other significant changes include the earnings from the recently acquired Enbridge Offshore Pipelines, lower interest expense and the absence of earnings from AltaGas, which was sold in 2004.

Earnings applicable to common shareholders are $93.6 million for the three months ended June 30, 2005, or $0.27 per share, compared with $248.4 million, or $0.74 per share, in 2004. The three-month

results reflect similar factors as those for the six-month period except the change in year-end creates a larger negative variance in the second quarter. The prior year comparatives in the second quarter represent gas distribution operations for January through March, which are typically the coldest months and contribute most to earnings, whereas the current quarter gas distribution operations are April through June.

Consolidated Earnings



	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Liquids Pipelines		53.6			53.7			106.6			106.3
Gas Pipelines		18.7			13.9			37.0			26.9
Sponsored Investments		14.5			14.6			32.9			30.0
Gas Distribution and Services¹		2.9			170.9			130.7			210.4
International		20.4			21.3			38.6			37.5
Corporate		(16.5	)		(26.0	)		(31.6	)		(50.3	)

		93.6			248.4			314.2			360.8


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 six months ended June 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 six months ended March 31, 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 more useful information to investors and shareholders as it provides clearer earnings trends and increased predictive value.



	Three months ended					Six months ended
(millions of Canadian dollars)	June 30,					June 30,
	2005		2004			2005			2004

GAAP earnings as reported		93.6		248.4			314.2			360.8
Non-operating factors and variances as per table below		2.0		(164.9	)		(13.6	)		(86.8	)

Adjusted Operating Earnings		95.6		83.5			300.6			274.0

Significant non-operating factors and variances affecting consolidated earnings are as follows:


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005		2004

Sponsored Investments
Dilution gains on EEP unit issuance		—			—			4.6		0.9

Gas Distribution and Services
Quarter lag earnings of EGD, Noverco and other¹		—			152.3			—		179.4
Calendar basis earnings of EGD, Noverco and other¹		—			21.7			—		(130.6	)
Colder/(warmer) than normal weather at EGD		(2.0	)		3.7			1.7		20.2
Elimination of seasonal distribution rates at EGD		—			(20.8	)		—		8.3
Dilution gain in Noverco (Gaz Metro unit issuance)		—			—			7.3		—
Dilution gain (AltaGas Income Trust)		—			8.0			—		8.0
Revalue future income taxes due to tax rate changes		—			—			—		0.6

Total significant non-operating factors and variances increasing/(decreasing) earnings		(2.0	)		164.9			13.6		86.8


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 first and second quarter earnings for EGD, Noverco and Other Gas Distribution Operations, which were for the three and six months ended March 31, 2004, have been eliminated and second and third quarter earnings, for the three and six months ended June 30, 2004, have been added. Other non-operating factors and variances that affected these businesses in 2004 are for the three and six months ended June 30, 2004, as was reported in the Company’s third quarter results for 2004.

Significant operating factors affecting earnings in 2005 include the following:

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

•		The Aux Sable liquids extraction plant reflects an improvement over the prior year due to improved fractionation margins.

•		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 net investment hedges to economically hedge a significant portion of the cash flows related to certain of these operations. However, for accounting purposes this does not eliminate the earnings volatility due to exchange rate differences and the translation of these foreign currency denominated earnings. During the first half of 2005, the Company received foreign currency denominated cash distributions and settled associated hedge transactions resulting in $5.4 million (2004 — $2.8 million) of incremental cash flows, which is not included in reported earnings.

Liquids Pipelines



	Three months ended					Six months ended
(millions of Canadian dollars)	June 30,					June 30,
	2005		2004			2005		2004

Enbridge System		39.5		41.5			78.4		82.7
Athabasca System		11.4		10.3			23.7		21.0
NW System		1.9		2.0			3.7		3.9
Feeder Pipelines and Other		0.8		(0.1	)		0.8		(1.3	)

		53.6		53.7			106.6		106.3

•		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.

•		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

Six months ended

(millions of Canadian dollars)

June 30,

2005

2004

2005

2004

Alliance Pipeline (US)

8.5

9.7

16.4

18.7

Enbridge Offshore Pipelines

6.6

—

12.6

—

Vector Pipeline

3.6

4.2

8.0

8.2

18.7

13.9

37.0

26.9

•		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 for $754.0 million.

•		Vector 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				Six months ended
(millions of Canadian dollars)	June 30,				June 30,
	2005		2004		2005		2004

Enbridge Income Fund (EIF)		8.4		7.5		16.7		15.0
Enbridge Energy Partners (EEP)		6.1		7.1		11.6		14.1
Dilution Gains (EEP)		—		—		4.6		0.9

		14.5		14.6		32.9		30.0

•		The 2005 results from EIF include higher preferred share dividends as well as higher incentive income consistent with EIF’s cash distribution increases in 2004.

•		EEP’s 2005 results reflect various factors including lower operating earnings, a stronger Canadian dollar and a lower ownership interest.

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

Gas Distribution and Services



	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Enbridge Gas Distribution¹		(2.8	)		132.4			88.3			143.9
Noverco¹		(2.1	)		15.0			19.8			28.6
CustomerWorks/ECS		6.2			4.3			12.3			9.2
Other Gas Distribution Operations¹		1.1			4.9			5.9			6.9
Enbridge Gas New Brunswick		1.0			0.6			2.0			1.7
Gas Services		(1.0	)		(0.6	)		(0.1	)		(1.0	)
Aux Sable		0.6			(1.8	)		3.8			(0.5	)
AltaGas Income Trust (investment sold in 2004)		—			15.6			—			20.3
Other		(0.1	)		0.5			(1.3	)		1.3

		2.9			170.9			130.7			210.4


¹		Earnings for 2005 are on a calendar year basis for the three and six months ended June 30, 2005; whereas, earnings for 2004 reflect earnings on a quarter-lag basis for the three and six months ended March 31, 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.

•		Improved fractionation margins at the Aux Sable gas processing facility continue to generate positive earnings.

•		The variance in Other is primarily the result of business development costs related to the proposed Rabaska LNG facility.


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Enbridge Gas Distribution — as reported		(2.8	)		132.4			88.3			143.9
Significant non-operating factors and variances:
quarter lag earnings ¹		—			(132.4	)		—			(143.9	)
calendar basis earnings ²		—			(22.7	)		—			109.7
warmer/(colder) than normal weather		2.0			(3.7	)		(1.7	)		(20.2	)
elimination of seasonal distribution rates		—			20.8			—			(8.3	)

		(0.8	)		(5.6	)		86.6			81.2


¹		These earnings are included in Enbridge’s consolidated earnings for the second quarter of 2004.

²		These earnings are included in Enbridge’s consolidated earnings for the third quarter of 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.

•		The $5.4 million increase in earnings at EGD, primarily during the second quarter, reflects the timing of various expenses as compared to the forecast cost of service that is included in revenues.


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Noverco — as reported		(2.1	)		15.0			19.8			28.6
Significant non-operating factors and variances:
quarter lag earnings ¹		—			(15.0	)		—			(28.6	)
calendar basis earnings ²		—			(0.1	)		—			14.9
dilution gain in Noverco (Gaz Metro unit issuance)		—			—			(7.3	)		—

		(2.1	)		(0.1	)		12.5			14.9


¹		These earnings are included in Enbridge’s consolidated earnings for the second quarter of 2004.

²		These earnings are included in Enbridge’s consolidated earnings for the third quarter of 2004.

•

Noverco results are lower due to increased future income tax expense in the second quarter of 2005. The Company recorded a $35 million cash dividend declared by Noverco in June as well as a $50 million adjustment for reciprocal dividends, both of which affect the accounting base of the investment and create a net future income tax expense. The remaining $35 million cash dividend was declared in July creating a future income tax recovery, to be recorded in the third quarter, and the full $70 million cash dividend was received on July 4, 2005.


	Three months ended					Six months ended
(millions of Canadian dollars)	June 30,					June 30,
	2005		2004			2005		2004

Other Gas Distribution Operations — as reported		1.1		4.9			5.9		6.9
Significant non-operating factors and variances:
quarter lag earnings ¹		—		(4.9	)		—		(6.9	)
calendar basis earnings ²		—		1.1			—		6.0

		1.1		1.1			5.9		6.0


¹		These earnings are included in Enbridge’s consolidated earnings for the second quarter of 2004.

²		These earnings are included in Enbridge’s consolidated earnings for the third quarter of 2004.

International


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

CLH		14.0			14.7			25.6			24.5
OCENSA/CITCol		8.0			8.1			16.2			15.9
Other		(1.6	)		(1.5	)		(3.2	)		(2.9	)

		20.4			21.3			38.6			37.5

•

The Company’s international investments continue to show strong performance with no significant variances.

Corporate


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Corporate		(16.5	)		(26.0	)		(31.6	)		(50.3	)

•

The decrease in corporate costs is primarily the result of lower interest expense in 2005 and higher business development activity in 2004, particularly in the second quarter. 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 July 28, 2005 at 9:30 a.m. Eastern time (7:30 a.m. Mountain time) to discuss the second quarter 2005 results. The call can be accessed at 1-800-299-0148, pass code of 90156282, 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 48398044; 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, which provides distribution services in the provinces of Ontario and Quebec, and in New York State; and is developing a gas distribution system for the Province of New Brunswick. The Company 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		Colin Gruending
(403) 231-3931		(403) 231-5919
E-mail: jim.rennie@enbridge.com		E-mail: colin.gruending@enbridge.com

ENBRIDGE INC.

HIGHLIGHTS¹

(unaudited; millions of Canadian dollars

Three months ended

Six months ended

except per share amounts)

June 30,

2005

2004

2005

2004

FINANCIAL

Earnings Applicable to Common Shareholders

Liquids Pipelines

53.6

53.7

106.6

106.3

Gas Pipelines

18.7

13.9

37.0

26.9

Sponsored Investments

14.5

14.6

32.9

30.0

Gas Distribution and Services

2.9

170.9

130.7

210.4

International

20.4

21.3

38.6

37.5

Corporate

(16.5

)

(26.0

)

(31.6

)

(50.3

)

93.6

248.4

314.2

360.8

Cash Provided By Operating Activities

Earnings plus charges/(credits) not affecting cash

295.9

368.2

664.8

607.9

Changes in operating assets and liabilities

55.7

331.7

356.4

284.1

351.6

699.9

1,021.2

892.0

Common Share Dividends

86.9

78.9

173.8

157.6

Earnings per Common Share

0.27

0.74

0.93

1.08

Diluted Earnings per Common Share

0.27

0.73

0.92

1.07

Dividends per Common Share

0.2500

0.2288

0.5000

0.4575

Weighted Average Common Shares Outstanding (millions)

336.9

334.0

Diluted Weighted Average Common Shares Outstanding (millions)

340.2

337.0

OPERATING

Liquids Pipelines²

Deliveries (thousands of barrels per day)

1,999

2,156

2,015

2,131

Barrel miles (billions)

173

191

345

376

Average haul (miles)

951

974

945

975

Gas Distribution and Services³

Volumes (billion cubic feet)

192

264

322

Number of active customers (thousands)

1,779

1,726

1,779

1,726

Degree day deficiency⁴

Actual

487

1,987

2,453

3,010

Forecast based on normal weather

546

1,870

2,440

2,807


^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 six months ended March 31, 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 six months ended June 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						Six months ended
(unaudited; millions of Canadian dollars, except per share amounts)	June 30,						June 30,
	2005			2004			2005			2004


Revenues
Gas sales		665.1			1,323.1			2,219.0			2,292.9
Transportation		463.1			452.4			1,008.6			861.4
Energy services		78.6			68.4			160.9			142.8

		1,206.8			1,843.9			3,388.5			3,297.1

Expenses
Gas costs		577.6			1,093.7			1,973.3			1,948.6
Operating and administrative		255.2			237.5			514.6			439.8
Depreciation		143.0			115.0			286.3			225.5

		975.8			1,446.2			2,774.2			2,613.9

Operating Income		231.0			397.7			614.3			683.2
Investment and Other Income		40.6			95.2			122.8			171.4
Interest Expense		(134.1	)		(123.1	)		(269.4	)		(247.2	)

		137.5			369.8			467.7			607.4
Income Taxes		(42.2	)		(119.7	)		(150.1	)		(243.2	)

Earnings		95.3			250.1			317.6			364.2
Preferred Share Dividends		(1.7	)		(1.7	)		(3.4	)		(3.4	)

Earnings Applicable to Common Shareholders		93.6			248.4			314.2			360.8


Earnings Per Common Share		0.27			0.74			0.93			1.08


Diluted Earnings Per Common Share		0.27			0.73			0.92			1.07

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS



	Six months ended
(unaudited; millions of Canadian dollars)	June 30,
	2005			2004

Retained Earnings at Beginning of Period		1,840.9			1,511.4
Earnings Applicable to Common Shareholders		314.2			360.8
Common Share Dividends		(173.8	)		(157.6	)
Dividends Paid to Reciprocal Shareholder		5.4			—
Dividend Reclassification Adjustment		51.2			—

Retained Earnings at End of Period		2,037.9			1,714.6

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three months ended						Six months ended
	June 30,						June 30,
(unaudited; millions of Canadian dollars)	2005			2004			2005			2004


Cash Provided By Operating Activities
Earnings		95.3			250.1			317.6			364.2
Charges/(credits) not affecting cash
Depreciation		143.0			115.0			286.3			225.5
Equity earnings less than/(in excess of) cash distributions		6.7			(23.4	)		(21.5	)		(55.1	)
Gain on reduction of ownership interest		—			(9.8	)		(15.6	)		(12.3	)
Future income taxes		47.9			33.0			85.0			82.0
Other		3.0			3.3			13.0			3.6
Changes in operating assets and liabilities		55.7			331.7			356.4			284.1

		351.6			699.9			1,021.2			892.0

Investing Activities
Acquisitions		(15.4	)		(13.7	)		(58.1	)		(17.4	)
Long-term investments		(0.8	)		—			(61.8	)		(16.2	)
Additions to property, plant and equipment		(116.4	)		(82.9	)		(199.5	)		(154.2	)
Changes in construction payable		(14.3	)		2.1			(0.3	)		(3.1	)
Changes in long-term notes receivable		(0.6	)		—			(0.6	)		—

		(147.5	)		(94.5	)		(320.3	)		(190.9	)

Financing Activities
Net change in short-term borrowings and short-term debt		(8.6	)		(417.2	)		(709.8	)		(582.7	)
Non-recourse short-term debt issued by joint ventures		12.5			—			11.9			—
Long-term debt issues		—			—			620.1			300.0
Long-term debt repayments		(100.0	)		(100.0	)		(396.9	)		(250.0	)
Non-recourse long-term debt repaid by joint ventures		(48.1	)		(15.3	)		(52.4	)		(29.5	)
Non-recourse long-term debt issued by joint ventures		—			—			6.8			—
Non-controlling interests		(7.2	)		(1.3	)		(11.9	)		(1.9	)
Common shares issued		12.0			4.8			39.4			24.3
Preferred share dividends		(1.7	)		(1.7	)		(3.4	)		(3.4	)
Common share dividends		(86.9	)		(78.9	)		(173.8	)		(157.6	)

		(228.0	)		(609.6	)		(670.0	)		(700.8	)

Increase/(Decrease) in Cash		(24.1	)		(4.2	)		30.9			0.3
Cash at Beginning of Period		160.5			108.6			105.5			104.1

Cash at End of Period		136.4			104.4			136.4			104.4

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION



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


Assets
Current Assets
Cash		136.4			105.5
Accounts receivable and other		1,232.8			1,451.9
Inventory		602.3			791.6

		1,971.5			2,349.0
Property, Plant and Equipment, net		10,328.0			9,066.5
Long-Term Investments		1,913.1			2,278.3
Receivable from Affiliate		180.9			171.7
Deferred Amounts and Other Assets		799.9			729.2
Goodwill		360.5			31.5
Intangible Assets		249.2			133.9
Future Income Taxes		120.7			145.0

		15,923.8			14,905.1


Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings		241.6			650.6
Accounts payable and other		1,166.9			1,275.9
Interest payable		78.3			83.8
Current maturities and short-term debt		541.2			703.9
Current portion of non-recourse long-term debt		84.2			30.2

		2,112.2			2,744.4
Long-Term Debt		6,166.5			6,053.3
Non-Recourse Long-Term Debt		1,674.3			665.2
Other Long-Term Liabilities		95.8			151.8
Future Income Taxes		951.3			797.3
Non-Controlling Interests		682.9			514.9

		11,683.0			10,926.9

Shareholders’ Equity
Share capital
Preferred shares		125.0			125.0
Common shares		2,321.8			2,282.4
Contributed surplus		7.1			5.4
Retained earnings		2,037.9			1,840.9
Foreign currency translation adjustment		(115.3	)		(139.8	)
Reciprocal shareholding		(135.7	)		(135.7	)

		4,240.8			3,978.2

		15,923.8			14,905.1

SEGMENTED INFORMATION

Three months ended June 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

214.1

98.3

61.7

830.7

2.0

—

1,206.8

Gas costs

—

(577.6

)

—

(577.6

)

Operating and administrative

(77.0

)

(23.1

)

(14.9

)

(133.8

)

(3.5

)

(2.9

)

(255.2

)

Depreciation

(36.5

)

(23.9

)

(17.9

)

(62.5

)

(0.3

)

(1.9

)

(143.0

)

Operating income

100.6

51.3

28.9

56.8

(1.8

)

(4.8

)

231.0

Investment and other income

(0.4

)

1.3

10.1

(1.4

)

22.8

8.2

40.6

Interest and preferred equity charges

(24.2

)

(21.6

)

(15.8

)

(42.6

)

—

(31.6

)

(135.8

)

Income taxes

(22.4

)

(12.3

)

(8.7

)

(9.9

)

(0.6

)

11.7

(42.2

)

Earnings applicable to common shareholders

53.6

18.7

14.5

2.9

20.4

(16.5

)

93.6

Three months ended June 30, 2004



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


Revenues		220.0			72.2			—			1,543.0			8.7			—			1,843.9
Gas costs		—			—			—			(1,093.7	)		—			—			(1,093.7	)
Operating and administrative		(81.1	)		(15.6	)		—			(124.9	)		(9.7	)		(6.2	)		(237.5	)
Depreciation		(35.8	)		(17.1	)		—			(60.8	)		(0.5	)		(0.8	)		(115.0	)

Operating income		103.1			39.5			—			263.6			(1.5	)		(7.0	)		397.7
Investment and other income		—			0.2			25.2			37.5			23.0			9.3			95.2
Interest and preferred equity charges		(25.4	)		(17.2	)		—			(43.7	)		(0.1	)		(38.4	)		(124.8	)
Income taxes		(24.0	)		(8.6	)		(10.6	)		(86.5	)		(0.1	)		10.1			(119.7	)

Earnings applicable to common shareholders		53.7			13.9			14.6			170.9			21.3			(26.0	)		248.4

Six months ended June 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

425.9

194.8

122.0

2,640.3

5.5

—

3,388.5

Gas costs

—

(1,973.3

)

—

(1,973.3

)

Operating and administrative

(151.2

)

(44.3

)

(28.1

)

(274.0

)

(8.1

)

(8.9

)

(514.6

)

Depreciation

(73.7

)

(48.1

)

(35.4

)

(125.6

)

(0.6

)

(2.9

)

(286.3

)

Operating income

201.0

102.4

58.5

267.4

(3.2

)

(11.8

)

614.3

Investment and other income

(1.2

)

1.3

30.8

25.2

42.9

23.8

122.8

Interest and preferred equity charges

(48.5

)

(42.7

)

(31.3

)

(87.3

)

—

(63.0

)

(272.8

)

Income taxes

(44.7

)

(24.0

)

(25.1

)

(74.6

)

(1.1

)

19.4

(150.1

)

Earnings applicable to common shareholders

106.6

37.0

32.9

130.7

38.6

(31.6

)

314.2

Six months ended June 30, 2004



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


Revenues		424.9			139.7			—			2,716.4			16.1			—			3,297.1
Gas costs		—			—			—			(1,948.6	)		—			—			(1,948.6	)
Operating and administrative		(149.2	)		(28.4	)		—			(232.8	)		(18.7	)		(10.7	)		(439.8	)
Depreciation		(71.7	)		(33.9	)		—			(117.5	)		(0.9	)		(1.5	)		(225.5	)

Operating income		204.0			77.4			—			417.5			(3.5	)		(12.2	)		683.2
Investment and other income		1.0			0.4			50.8			59.3			42.3			17.6			171.4
Interest and preferred equity charges		(50.4	)		(34.0	)		—			(86.7	)		(0.1	)		(79.4	)		(250.6	)
Income taxes		(48.3	)		(16.9	)		(20.8	)		(179.7	)		(1.2	)		23.7			(243.2	)

Earnings/(loss) applicable to common shareholders		106.3			26.9			30.0			210.4			37.5			(50.3	)		360.8


1.		Gas Distribution and Services results for 2004 were consolidated on a one-quarter-lag basis and therefore reflect the three and six month periods ended March 31, 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 six month periods ended June 30, 2005.

Enbridge Inc.
Management’s Discussion & Analysis
For the Three and Six Months Ended June 30, 2005
Dated July 27, 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 six months ended June 30, 2005.

Consolidated Earnings


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Liquids Pipelines		53.6			53.7			106.6			106.3
Gas Pipelines		18.7			13.9			37.0			26.9
Sponsored Investments		14.5			14.6			32.9			30.0
Gas Distribution and Services¹		2.9			170.9			130.7			210.4
International		20.4			21.3			38.6			37.5
Corporate		(16.5	)		(26.0	)		(31.6	)		(50.3	)

		93.6			248.4			314.2			360.8


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 six months ended June 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 six months ended March 31, 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.

Earnings applicable to common shareholders are $314.2 million for the six months ended June 30, 2005, or $0.93 per share, compared with $360.8 million, or $1.08 per share, in 2004. The $46.6 million decrease in earnings is due to the previously announced change in the year-end of the gas distribution operations and the elimination of seasonal distribution rates at EGD. These factors create a lack of comparability between periods, however a reconciliation is provided below. Other significant changes include the earnings from the recently acquired Enbridge Offshore Pipelines, lower interest expense and the absence of earnings from AltaGas, which was sold in 2004.

Earnings applicable to common shareholders are $93.6 million for the three months ended June 30, 2005, or $0.27 per share, compared with $248.4 million, or $0.74 per share, in 2004. The three-month results reflect similar factors as those for the six-month period except that the change in year-end creates a larger negative variance in the second quarter. The prior year comparatives in the second quarter represent gas distribution operations for January through March, which are typically the coldest months and contribute most to earnings, whereas the current quarter gas distribution operations are April through June.

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

- 1 -

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.

Significant non-operating factors and variances affecting consolidated earnings are as follows:


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005		2004


Sponsored Investments
Dilution gains on the issue of EEP units		—			—			4.6		0.9
Gas Distribution and Services
Quarter lag earnings for EGD and others¹		—			152.3			—		179.4
Calendar basis earnings for EGD and others¹		—			21.7			—		(130.6	)
Colder/(warmer) than normal weather at EGD		(2.0	)		3.7			1.7		20.2
Elimination of seasonal distribution rates at EGD		—			(20.8	)		—		8.3
Dilution gain in Noverco (Gaz Metro unit issuance)		—			—			7.3		—
Dilution gain, AltaGas Income Trust		—			8.0			—		8.0
Revalue future income taxes due to tax rate changes		—			—			—		0.6


Total significant non-operating factors and variances increasing/(decreasing) earnings		(2.0	)		164.9			13.6		86.8


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 first and second quarter earnings for EGD, Noverco and Other Gas Distribution Operations, which were for the three and six months ended March 31, 2004, have been eliminated and second and third quarter earnings, for the three and six months ended June 30, 2004, have been added. Other non-operating factors and variances that affected these businesses in 2004 are for the three and six months ended June 30, 2004, as was reported in the Company’s third quarter results for 2004.

Significant operating factors affecting earnings in 2005 include the following:

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

•		The Aux Sable liquids extraction plant reflects an improvement over the prior year due to improved fractionation margins.

•		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 net investment hedges to economically hedge a significant portion of the cash flows related to certain of these operations. However, for accounting purposes, this does not eliminate the earnings volatility due to exchange rate differences and the translation of these foreign currency denominated earnings. During the first half of 2005, the Company received foreign currency denominated cash distributions and settled associated hedge transactions resulting in $5.4 million (2004 — $2.8 million) of incremental cash flows, which is not included in reported earnings.

- 2 -

RECENT DEVELOPMENTS

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 will be 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 will be based on a revenue requirement calculated in reference to the 2004 revenue requirement, adjusted annually for inflation. The costs of income taxes and power will be born by shippers with Enbridge guaranteeing $5 million in power savings and sharing in any power savings beyond the guaranteed amount. The revenue requirement will also include an $18 million annual pipeline integrity allowance and half of the operating costs associated with the service metrics, described below. The revenue requirement will be 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 will provide Enbridge with the opportunity to increase earnings by achieving performance targets under new 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 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. 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.

The Company has filed interim tolls reflecting the terms of the MOU with the National Energy Board.

Gateway Condensate Import Pipeline

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 condensate import pipeline is expected to cost approximately $1.7 billion on a stand-alone basis. Enbridge is conducting a two-phase Open Season from July 2005 to September 2005 to confirm shipper support for the condensate import pipeline.

The Gateway Project also includes a crude oil export pipeline, which would transport crude oil from Edmonton, Alberta 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 $600 million could be realized. A separate Open Season for the crude oil export pipeline will be held later in 2005.

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

- 3 -

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 extension and the Canadian portion of the expansion and EEP, Enbridge’s 11.2%-owned equity investment, would undertake the U.S. expansion. The expansion would consist of three separate phases that would add a total of 400,000 barrels per day (bpd) of capacity. The extension would involve the construction of a new 30-inch diameter, 300,000 bpd pipeline. The cost of the expansion would be approximately US$135 million to Enbridge and approximately US$880 million to EEP. The cost of the extension would be approximately US$320 million to Enbridge and, if the extension and expansion were completed as a single project, cost savings of approximately US$120 million could be realized.

Enbridge and EEP are conducting an Open Season to confirm shipper support. Assuming all necessary approvals and other contingencies are satisfied, the complete program could be in service as early as the first quarter of 2009.

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 to existing Gulf 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.

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 during the first quarter of 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 for approval of the 2006 rates, under cost of service. 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 Ontario Energy Board (OEB), mandates that distributors, including Enbridge Gas Distribution (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.

- 4 -

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 EDG and Union Gas to change their billing systems to adhere to GDAR.

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

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

The agreements provide for an initial contract volume of up to 60,000 barrels per day 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 a proposed new pipeline – the Waupisoo Pipeline – to move crude oil from the Cheecham terminal to Edmonton.

FINANCIAL RESULTS

Liquids Pipelines

Earnings


	Three months ended					Six months ended
(millions of Canadian dollars)	June 30,					June 30,
	2005		2004			2005		2004
Enbridge System		39.5		41.5			78.4		82.7
Athabasca System		11.4		10.3			23.7		21.0
NW System		1.9		2.0			3.7		3.9
Feeder Pipelines and Other		0.8		(0.1	)		0.8		(1.3	)

		53.6		53.7			106.6		106.3

Earnings are $106.6 million for the six months ended June 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 Frontier Pipeline earnings, which are included in Feeder Pipelines and Other, and Athabasca System earnings.

- 5 -

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 to be 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.

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 June 30, 2005, earnings are consistent with the prior year and reflect similar offsetting factors as the six-month results.

Gas Pipelines

Earnings

Three months ended

Six months ended

(millions of Canadian dollars)

June 30,

2005

2004

2005

2004

Alliance Pipeline (US)

8.5

9.7

16.4

18.7

Enbridge Offshore Pipelines

6.6

—

12.6

—

Vector Pipeline

3.6

4.2

8.0

8.2

18.7

13.9

37.0

26.9

Earnings are $37.0 million for the six months ended June 30, 2005, compared with $26.9 million for the six months ended June 30, 2004. The increase is due to the inclusion of Enbridge Offshore Pipelines, which was acquired on December 31, 2004 for $754.0 million.

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

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 $18.7 million for the second quarter of 2005, compared with $13.9 million for the same period of 2004. Second quarter earnings in 2005 reflect the inclusion of Enbridge Offshore Pipelines partially offset by the impact of the stronger Canadian dollar on Alliance Pipeline (US) and Vector Pipeline.

- 6 -

Sponsored Investments

Earnings

Three months ended

Six months ended

(millions of Canadian dollars)

June 30,

2005

2004

2005

2004

Enbridge Income Fund (EIF)

8.4

7.5

16.7

15.0

Enbridge Energy Partners (EEP)

6.1

7.1

11.6

14.1

Dilution Gains (EEP)

—

4.6

0.9

14.5

14.6

32.9

30.0

Earnings for the six months ended June 30, 2005 are $32.9 million compared with $30.0 million in the same period of 2004. The variance reflects higher earnings from EIF and a larger dilution gain in 2005, offset by lower earnings from EEP.

The 2005 results from EIF include higher preferred share dividends, as well as higher incentive income, consistent with EIF’s cash distribution increases in 2004.

EEP’s 2005 results reflect a number of factors including lower operating earnings, a stronger Canadian dollar and a lower ownership interest.

In the first quarter of each year, EEP issued additional common units and, as Enbridge did not participate in these offerings, dilution gains resulted.

For the three months ended June 30, 2005, earnings are $14.5 million compared with $14.6 million for the same period in 2004, reflecting lower earnings in EEP offset by higher earnings from EIF, similar to the six-month period.

Gas Distribution and Services

Earnings


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004
Enbridge Gas Distribution¹		(2.8	)		132.4			88.3			143.9
Noverco¹		(2.1	)		15.0			19.8			28.6
CustomerWorks/ECS		6.2			4.3			12.3			9.2
Other Gas Distribution Operations¹		1.1			4.9			5.9			6.9
Enbridge Gas New Brunswick		1.0			0.6			2.0			1.7
Gas Services		(1.0	)		(0.6	)		(0.1	)		(1.0	)
Aux Sable		0.6			(1.8	)		3.8			(0.5	)
AltaGas Income Trust (investment sold in 2004)		—			15.6			—			20.3
Other		(0.1	)		0.5			(1.3	)		1.3

		2.9			170.9			130.7			210.4


¹		Earnings for 2005 are on a calendar year basis for the three and six months ended June 30, 2005, whereas earnings for 2004 reflect earnings on a quarter lag basis for the three and six months ended March 31, 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.

- 7 -

Earnings are $130.7 million for the six months ended June 30, 2005 compared with $210.4 million for the six months ended June 30, 2004. The earnings variance reflects 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 June 30, 2005 primarily reflect the change from quarter lag consolidation to calendar year consolidation for EGD, Noverco and Other Gas Distribution Operations. This variance is most pronounced in the three months ended June 30 because the prior year comparatives represent the results for January through March. These months are typically the coldest of the year and contribute the most to earnings.

At the Aux Sable gas processing facility, improved fractionation margins continue to generate positive earnings.

The variance in Other is primarily the result of business development costs related to the proposed Rabaska LNG facility.


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Enbridge Gas Distribution — as reported		(2.8	)		132.4			88.3			143.9
Significant non-operating factors and variances:
quarter lag earnings¹		—			(132.4	)		—			(143.9	)
calendar basis earnings²		—			(22.7	)		—			109.7
warmer/(colder) than normal weather		2.0			(3.7	)		(1.7	)		(20.2	)
elimination of seasonal distribution rates		—			20.8			—			(8.3	)

		(0.8	)		(5.6	)		86.6			81.2


¹		These earnings are included in Enbridge’s consolidated earnings for the second quarter of 2004.

²		These earnings are included in Enbridge’s consolidated earnings for the third quarter of 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 table above, is the effect of applying the uniform rate to 2004 results and volumes.

The $5.4 million increase in earnings at EGD, primarily during the second quarter, reflects the timing of various expenses as compared to the forecast cost of service that is included in revenues.

- 8 -


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Noverco — as reported		(2.1	)		15.0			19.8			28.6
Significant non-operating factors and variances:
quarter lag earnings¹		—			(15.0	)		—			(28.6	)
calendar basis earnings²		—			(0.1	)		—			14.9
dilution gain in Noverco (Gaz Metro unit issuance)		—			—			(7.3	)		—

		(2.1	)		(0.1	)		12.5			14.9


¹		These earnings are included in Enbridge’s consolidated earnings for the second quarter of 2004.

²		These earnings are included in Enbridge’s consolidated earnings for the third quarter of 2004.

Noverco results are lower due to increased future income tax expense in the second quarter of 2005. The Company recorded a $35 million cash dividend declared by Noverco in June as well as a $50 million adjustment for reciprocal dividends, both of which affect the accounting base of the investment and create a net future income tax expense. The remaining $35 million dividend was declared in July creating a future income tax recovery, which will be recorded in the third quarter. The full $70 million cash dividend was received on July 4, 2005.


	Three months ended					Six months ended
(millions of Canadian dollars)	June 30,					June 30,
	2005		2004			2005		2004

Other Gas Distribution Operations — as reported		1.1		4.9			5.9		6.9
Significant non-operating factors and variances:
quarter lag earnings¹		—		(4.9	)		—		(6.9	)
calendar basis earnings²		—		1.1			—		6.0

		1.1		1.1			5.9		6.0


¹		These earnings are included in Enbridge’s consolidated earnings for the second quarter of 2004.

²		These earnings are included in Enbridge’s consolidated earnings for the third quarter of 2004.

International

Earnings


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

CLH		14.0			14.7			25.6			24.5
OCENSA/CITCol		8.0			8.1			16.2			15.9
Other		(1.6	)		(1.5	)		(3.2	)		(2.9	)

		20.4			21.3			38.6			37.5

Earnings for the six months ended June 30, 2005 are $38.6 million, an increase of $1.1 million for the same period in 2004. The increase is attributable to increased earnings from CLH and

- 9 -

OCENSA/CITCol. These investments continue to show strong performance with no significant variances from the prior year.

For the three months ended June 30, 2005, there is no significant change in earnings from the same period in the prior year.

Corporate

Costs


	Three months ended						Six months ended
(millions of Canadian dollars)	June 30,						June 30,
	2005			2004			2005			2004

Corporate		(16.5	)		(26.0	)		(31.6	)		(50.3	)

Corporate costs total $31.6 million for six months ended June 30, 2005, a decrease of $18.7 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, particularly in the second quarter. 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 six months ended June 30, 2005, whereas cash flows for 2004 reflect cash flows from EGD, Noverco and Other Gas Distribution Operations for the three and six months ended March 31, 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.

Commencing January 1, 2005, Enbridge consolidates the accounts of EIF. This change in accounting policy results in non-cash increases in many of the Company’s asset and liability accounts.

Operating Activities

Cash from operations for the six months ended June 30, 2005, is $1,021.2 million and reflects an increase of $129.2 million from the same period in the prior year. Before changes in operating assets and liabilities, cash from operations increased $56.9 million. Although earnings are lower, the non-cash portion is higher resulting in more cash from earnings. Changes in operating assets and liabilities increased $72.3 million from the six months ended June 30, 2004 primarily due to changes in working capital at EGD, which fluctuates seasonally. Due to the elimination of the quarter lag basis of consolidation described above, these amounts are not comparable.

For the three months ended June 30, 2005, cash from operating activities was $351.6 million, a decrease of $348.3 million from the same period in the prior year. The decrease results mainly from changes in operating assets and liabilities in EGD. The periods are not comparable due to the elimination of the quarter lag basis of accounting, which is most pronounced in the second quarter.

- 10 -

Investing Activities

Cash used for investing activities during the six months ended June 30, 2005 is $320.3 million and $147.5 million for the three months ended June 30, 2005 compared to $190.9 million and $94.5 million for the six and three months ended June 30, 2004, respectively. The increases reflect the acquisitions of U.S. Oil and the remaining 20% of Garden Banks in the first quarter of 2005 and the acquisition of the remaining 10% of the Spearhead Pipeline during the second quarter of 2005. In the first quarter of 2005, the Company paid a deferred acquisition cost that was contingent on CLH meeting certain target volumes.

Financing Activities

The Company’s debt to capitalization ratio was 62.1% compared with 65.1% on December 31, 2004, continuing the Company’s trend of debt repayment.

Financing activities during the six months ended June 30, 2005 resulted in a use of cash of $670.0 million compared to $700.8 million in the six months ended June 30, 2004. The Company used the proceeds of long-term debt issuances to repay short-term debt during the first quarter of 2005.

During the three months ended June 30, 2005, financing activities resulted in a use of $228.0 million compared to $609.6 million in the comparable period in 2004. The Company repaid $100 million long-term debt that matured in the second quarter of 2005. In the second quarter of 2004, there were higher repayments of short-term borrowings in EGD, which uses short-term borrowings to finance gas in storage. In 2004, repayments were higher, commensurate with the periods represented in the quarter lag basis of accounting, which was eliminated in 2005.

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.

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.

- 11 -

SELECTED QUARTERLY FINANCIAL INFORMATION¹


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

Revenue		1,206.8		2,181.7		1,960.0		1283.4		1,843.9		1,453.2		854.3		1,068.1

Earnings applicable to common shareholders		93.6		220.6		104.8		179.7		248.4		112.4		27.3		90.7
Earnings per common share		0.27		0.66		0.32		0.54		0.74		0.34		0.08		0.27
Diluted earnings per common share		0.27		0.65		0.32		0.53		0.73		0.34		0.08		0.27
Dividends per common share		0.2500		0.2500		0.22875		0.22875		0.22875		0.22875		0.2075		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 the Company’s gas distribution business (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 no earnings impact on a 12 consecutive month basis.

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.

- 12 -

OUTSTANDING SHARE DATA


	Number of Shares
Common Shares – issued and outstanding (voting equity shares)		348,306,533

Preference Shares, Series A (non-voting equity shares)		5,000,000
Total issued and outstanding stock options (6,297,707 vested)		11,895,907

Outstanding share data information is provided as at July 18, 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.

- 13 -

ENBRIDGE INC.

HIGHLIGHTS¹

(unaudited; millions of Canadian dollars

Three months ended

Six months ended

except per share amounts)

June 30,

2005

2004

2005

2004

FINANCIAL

Earnings Applicable to Common Shareholders

Liquids Pipelines

53.6

53.7

106.6

106.3

Gas Pipelines

18.7

13.9

37.0

26.9

Sponsored Investments

14.5

14.6

32.9

30.0

Gas Distribution and Services

2.9

170.9

130.7

210.4

International

20.4

21.3

38.6

37.5

Corporate

(16.5

)

(26.0

)

(31.6

)

(50.3

)

93.6

248.4

314.2

360.8

Cash Provided By Operating Activities

Earnings plus charges/(credits) not affecting cash

295.9

368.2

664.8

607.9

Changes in operating assets and liabilities

55.7

331.7

356.4

284.1

351.6

699.9

1,021.2

892.0

Common Share Dividends

86.9

78.9

173.8

157.6

Earnings per Common Share

0.27

0.74

0.93

1.08

Diluted Earnings per Common Share

0.27

0.73

0.92

1.07

Dividends per Common Share

0.2500

0.2288

0.5000

0.4575

Weighted Average Common Shares Outstanding (millions)

336.9

334.0

Diluted Weighted Average Common Shares Outstanding (millions)

340.2

337.0

OPERATING

Liquids Pipelines²

Deliveries (thousands of barrels per day)

1,999

2,156

2,015

2,131

Barrel miles (billions)

173

191

345

376

Average haul (miles)

951

974

945

975

Gas Distribution and Services³

Volumes (billion cubic feet)

192

264

322

Number of active customers (thousands)

1,779

1,726

1,779

1,726

Degree day deficiency⁴

Actual

487

1,987

2,453

3,010

Forecast based on normal weather

546

1,870

2,440

2,807


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 six months ended March 31, 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 six months ended June 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.

- 14 -

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS



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

Revenues
Gas sales		665.1			1,323.1			2,219.0			2,292.9
Transportation		463.1			452.4			1,008.6			861.4
Energy services		78.6			68.4			160.9			142.8

		1,206.8			1,843.9			3,388.5			3,297.1

Expenses
Gas costs		577.6			1,093.7			1,973.3			1,948.6
Operating and administrative		255.2			237.5			514.6			439.8
Depreciation		143.0			115.0			286.3			225.5

		975.8			1,446.2			2,774.2			2,613.9

Operating Income		231.0			397.7			614.3			683.2
Investment and Other Income		40.6			95.2			122.8			171.4
Interest Expense		(134.1	)		(123.1	)		(269.4	)		(247.2	)

		137.5			369.8			467.7			607.4
Income Taxes		(42.2	)		(119.7	)		(150.1	)		(243.2	)

Earnings		95.3			250.1			317.6			364.2
Preferred Share Dividends		(1.7	)		(1.7	)		(3.4	)		(3.4	)

Earnings Applicable to Common Shareholders		93.6			248.4			314.2			360.8


Earnings Per Common Share		0.27			0.74			0.93			1.08


Diluted Earnings Per Common Share		0.27			0.73			0.92			1.07


See accompanying notes to the unaudited consolidated financial statements.

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

Six months ended

(unaudited; millions of Canadian dollars)

June 30,

2005

2004

Retained Earnings at Beginning of Period

1,840.9

1,511.4

Earnings Applicable to Common Shareholders

314.2

360.8

Common Share Dividends

(173.8

)

(157.6

)

Dividends Paid to Reciprocal Shareholder

5.4

—

Dividend Reclassification Adjustment (Note 3)

51.2

—

Retained Earnings at End of Period

2,037.9

1,714.6


See accompanying notes to the unaudited consolidated financial statements.

- 15 -

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three months ended						Six months ended
	June 30,						June 30,
(unaudited; millions of Canadian dollars)	2005			2004			2005			2004

Cash Provided By Operating Activities
Earnings		95.3			250.1			317.6			364.2
Charges/(credits) not affecting cash
Depreciation		143.0			115.0			286.3			225.5
Equity earnings less than/(in excess of) cash distributions		6.7			(23.4	)		(21.5	)		(55.1	)
Gain on reduction of ownership interest		—			(9.8	)		(15.6	)		(12.3	)
Future income taxes		47.9			33.0			85.0			82.0
Other		3.0			3.3			13.0			3.6
Changes in operating assets and liabilities		55.7			331.7			356.4			284.1

		351.6			699.9			1,021.2			892.0

Investing Activities
Acquisitions		(15.4	)		(13.7	)		(58.1	)		(17.4	)
Long-term investments		(0.8	)		—			(61.8	)		(16.2	)
Additions to property, plant and equipment		(116.4	)		(82.9	)		(199.5	)		(154.2	)
Changes in construction payable		(14.3	)		2.1			(0.3	)		(3.1	)
Changes in long-term notes receivable		(0.6	)		—			(0.6	)		—

		(147.5	)		(94.5	)		(320.3	)		(190.9	)

Financing Activities
Net change in short-term borrowings and short-term debt		(8.6	)		(417.2	)		(709.8	)		(582.7	)
Non-recourse short-term debt issued by joint ventures		12.5			—			11.9			—
Long-term debt issues		—			—			620.1			300.0
Long-term debt repayments		(100.0	)		(100.0	)		(396.9	)		(250.0	)
Non-recourse long-term debt repaid by joint ventures		(48.1	)		(15.3	)		(52.4	)		(29.5	)
Non-recourse long-term debt issued by joint ventures		—			—			6.8			—
Non-controlling interests		(7.2	)		(1.3	)		(11.9	)		(1.9	)
Common shares issued		12.0			4.8			39.4			24.3
Preferred share dividends		(1.7	)		(1.7	)		(3.4	)		(3.4	)
Common share dividends		(86.9	)		(78.9	)		(173.8	)		(157.6	)

		(228.0	)		(609.6	)		(670.0	)		(700.8	)

Increase/(Decrease) in Cash		(24.1	)		(4.2	)		30.9			0.3
Cash at Beginning of Period		160.5			108.6			105.5			104.1

Cash at End of Period		136.4			104.4			136.4			104.4


See accompanying notes to the unaudited consolidated financial statements.

- 16 -

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

June 30,

December 31,

(unaudited; millions of Canadian dollars)

2005

2004

Assets

Current Assets

Cash

136.4

105.5

Accounts receivable and other

1,232.8

1,451.9

Inventory

602.3

791.6

1,971.5

2,349.0

Property, Plant and Equipment, net

10,328.0

9,066.5

Long-Term Investments

1,913.1

2,278.3

Receivable from Affiliate

180.9

171.7

Deferred Amounts and Other Assets

799.9

729.2

Goodwill

360.5

31.5

Intangible Assets

249.2

133.9

Future Income Taxes

120.7

145.0

15,923.8

14,905.1

Liabilities and Shareholders’ Equity

Current Liabilities

Short-term borrowings

241.6

650.6

Accounts payable and other

1,166.9

1,275.9

Interest payable

78.3

83.8

Current maturities and short-term debt

541.2

703.9

Current portion of non-recourse long-term debt

84.2

30.2

2,112.2

2,744.4

Long-Term Debt

6,166.5

6,053.3

Non-Recourse Long-Term Debt

1,674.3

665.2

Other Long-Term Liabilities

95.8

151.8

Future Income Taxes

951.3

797.3

Non-Controlling Interests

682.9

514.9

11,683.0

10,926.9

Shareholders’ Equity

Share capital

Preferred shares

125.0

125.0

Common shares

2,321.8

2,282.4

Contributed surplus

7.1

5.4

Retained earnings

2,037.9

1,840.9

Foreign currency translation adjustment

(115.3

)

(139.8

)

Reciprocal shareholding

(135.7

)

(135.7

)

4,240.8

3,978.2

15,923.8

14,905.1


See accompanying notes to the unaudited consolidated financial statements.

- 17 -

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. SIGNIFICANT ACCOUNTING POLICIES

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.

- 18 -

Consolidating EIF had the following impact on the financial statements:


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

Assets
Cash		12.1
Accounts receivable and other		25.6
Property, plant and equipment, net		1,238.1
Deferred amounts and other assets		37.2
Goodwill		308.1
Intangible assets		105.7

		1,726.8
Less: Liabilities
Accounts payable and other		20.3
Current portion of non-recourse long-term debt		35.3
Non recourse long-term debt		1,023.6
Other long-term liabilities		6.9
Future income taxes		90.0
Non-controlling interests		170.3

		1,346.4

		380.4
Elimination of investment in EIF		(380.4	)

Net financial position impact	*nil*


Statement of Earnings	Three months ended			Six months ended
(millions of Canadian dollars)	June 30, 2005			June 30, 2005

Transportation revenue		61.7			122.0
Less: Expenses
Operating and administrative		14.6			27.8
Depreciation		17.9			35.4
Investment and other income		1.7			4.0
Interest expense		15.8			31.3
Income taxes		—			(0.2	)

		50.0			98.3

		11.7			23.7
Elimination of EIF investment income		(11.7	)		(23.7	)

Net earnings impact	*nil*			*nil*


Statement of Cash Flows	Three months ended			Six months ended
(millions of Canadian dollars)	June 30, 2005			June 30, 2005

Operating activities		(0.1	)		30.6
Investing activities		(1.8	)		(3.1	)
Financing activities		(23.6	)		(30.2	)

Net cashflow impact		(25.5	)		(2.7	)

- 19 -

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 six months ended June 30, 2004, interest expense increased $10.3 million and $20.7 million, income taxes decreased $3.4 million and $6.8 million and preferred security distributions of $6.9 million and $13.9 million were eliminated.

2. SEGMENTED INFORMATION



Three months ended June 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

214.1

98.3

61.7

830.7

2.0

—

1,206.8

Gas costs

—

(577.6

)

—

(577.6

)

Operating and administrative

(77.0

)

(23.1

)

(14.9

)

(133.8

)

(3.5

)

(2.9

)

(255.2

)

Depreciation

(36.5

)

(23.9

)

(17.9

)

(62.5

)

(0.3

)

(1.9

)

(143.0

)

Operating income

100.6

51.3

28.9

56.8

(1.8

)

(4.8

)

231.0

Investment and other income

(0.4

)

1.3

10.1

(1.4

)

22.8

8.2

40.6

Interest and preferred equity charges

(24.2

)

(21.6

)

(15.8

)

(42.6

)

—

(31.6

)

(135.8

)

Income taxes

(22.4

)

(12.3

)

(8.7

)

(9.9

)

(0.6

)

11.7

(42.2

)

Earnings applicable to common shareholders

53.6

18.7

14.5

2.9

20.4

(16.5

)

93.6



Three months ended June 30, 2004


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

Revenues		220.0			72.2			—			1,543.0			8.7			—			1,843.9
Gas costs		—			—			—			(1,093.7	)		—			—			(1,093.7	)
Operating and administrative		(81.1	)		(15.6	)		—			(124.9	)		(9.7	)		(6.2	)		(237.5	)
Depreciation		(35.8	)		(17.1	)		—			(60.8	)		(0.5	)		(0.8	)		(115.0	)

Operating income		103.1			39.5			—			263.6			(1.5	)		(7.0	)		397.7
Investment and other income		—			0.2			25.2			37.5			23.0			9.3			95.2
Interest and preferred equity charges		(25.4	)		(17.2	)		—			(43.7	)		(0.1	)		(38.4	)		(124.8	)
Income taxes		(24.0	)		(8.6	)		(10.6	)		(86.5	)		(0.1	)		10.1			(119.7	)

Earnings applicable to common shareholders		53.7			13.9			14.6			170.9			21.3			(26.0	)		248.4

- 20 -



Six months ended June 30, 2005

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services¹

International

Corporate

Consolidated

Revenues

425.9

194.8

122.0

2,640.3

5.5

—

3,388.5

Gas costs

—

(1,973.3

)

—

(1,973.3

)

Operating and administrative

(151.2

)

(44.3

)

(28.1

)

(274.0

)

(8.1

)

(8.9

)

(514.6

)

Depreciation

(73.7

)

(48.1

)

(35.4

)

(125.6

)

(0.6

)

(2.9

)

(286.3

)

Operating income

201.0

102.4

58.5

267.4

(3.2

)

(11.8

)

614.3

Investment and other income

(1.2

)

1.3

30.8

25.2

42.9

23.8

122.8

Interest and preferred equity charges

(48.5

)

(42.7

)

(31.3

)

(87.3

)

—

(63.0

)

(272.8

)

Income taxes

(44.7

)

(24.0

)

(25.1

)

(74.6

)

(1.1

)

19.4

(150.1

)

Earnings/(loss) applicable to common shareholders

106.6

37.0

32.9

130.7

38.6

(31.6

)

314.2



Six months ended June 30, 2004


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

Revenues		424.9			139.7			—			2,716.4			16.1			—			3,297.1
Gas costs		—			—			—			(1,948.6	)		—			—			(1,948.6	)
Operating and administrative		(149.2	)		(28.4	)		—			(232.8	)		(18.7	)		(10.7	)		(439.8	)
Depreciation		(71.7	)		(33.9	)		—			(117.5	)		(0.9	)		(1.5	)		(225.5	)

Operating income		204.0			77.4			—			417.5			(3.5	)		(12.2	)		683.2
Investment and other income		1.0			0.4			50.8			59.3			42.3			17.6			171.4
Interest and preferred equity charges		(50.4	)		(34.0	)		—			(86.7	)		(0.1	)		(79.4	)		(250.6	)
Income taxes		(48.3	)		(16.9	)		(20.8	)		(179.7	)		(1.2	)		23.7			(243.2	)

Earnings/(loss) applicable to common shareholders		106.3			26.9			30.0			210.4			37.5			(50.3	)		360.8


1.		Gas Distribution and Services results for 2004 were consolidated on a one-quarter-lag basis and therefore reflect the three and six month periods ended March 31, 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 six month periods ended June 30, 2005.

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).

Noverco

During the period ended June 30, 2005, a special dividend of $35.3 million was declared by Noverco, an equity investee. This special dividend was received on July 4, 2005, concurrent with the declaration

- 21 -

and receipt of a second special dividend of a further $35.3 million. On June 30, 2005, the equity investment balance was reduced by $35.3 million to reflect the impact of the first special dividend on the accounts of the Company.

On June 30, 2005, the Company reclassified $51.2 million in dividends paid to Noverco. The reclassification increases equity investments and retained earnings by $51.2 million and represents 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 six months ended June 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 six months ended June 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 six months ended June 30, 2005. The PSUs granted in 2005 mature January 1, 2008. Compensation costs for PSUs are accounted for over the three-year 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.

- 22 -


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

Earnings applicable to common shareholders As reported		93.6			248.4			314.2			360.8
Total stock-based compensation expense ¹		(3.2	)		(2.2	)		(5.9	)		(4.0	)
Included as an expense in the statement of earnings ²		2.2			1.2			3.9			2.0

Pro forma earnings		92.6			247.4			312.2			358.8


Earnings per share
As reported		0.27			0.74			0.93			1.08

Pro forma		0.27			0.73			0.93			1.07


Diluted earnings per share
As reported		0.27			0.73			0.92			1.07

Pro forma		0.27			0.73			0.92			1.07


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

2.		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.

3.		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.

Net Pension and OPEB Costs Recognized


	Three months ended						Six months ended
	June 30,						June 30,
(millions of Canadian dollars)	2005			2004			2005			2004

Benefits earned during the period		8.1			7.4			16.2			14.7
Interest cost on projected benefit obligations		15.9			14.9			31.7			29.5
Expected return on plan assets		(18.9	)		(17.8	)		(37.8	)		(35.5	)
Amortization and deferral of unrecognized amounts		3.0			3.7			6.2			7.6
Amount charged to Enbridge Energy Partners L.P.		(2.6	)		(2.3	)		(5.1	)		(4.5	)

Pension and OPEB costs recognized		5.5			5.9			11.2			11.8

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 $8.8 million for the six month period ended June 30, 2005 (2004 — $8.1 million) and $4.3 million for the three month period ended June 30, 2005 (2004 — $4.1 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						Six months ended
	June 30,						June 30,
(millions of dollars except per share amounts)	2005			2004			2005			2004

Earnings under Canadian GAAP		93.6			248.4			314.2			360.8
U.S. GAAP earnings adjustments¹		—			—			(6.6	)		—
Tax effect of the above adjustments		—			—			2.6			—

Earnings under U.S. GAAP		93.6			248.4			310.2			360.8
Unrealized net gain/(loss) on cash flow hedges⁵		(20.0	)		(0.5	)		47.2			(26.9	)
Foreign currency translation adjustment⁵		24.2			21.0			34.6			36.9

Comprehensive income		97.8			268.9			392.0			370.8

Earnings per common share		0.27			0.74			0.92			1.08

Diluted earnings per common share		0.27			0.73			0.91			1.07

Financial Position

(millions of dollars)



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

Cash ⁶		136.4			136.4			105.5			120.3
Accounts receivable and other ^4,5,6		1,232.8			1,284.8			1,451.9			1,483.6
Property, plant and equipment, net ⁶		10,328.0			10,328.0			9,066.5			10,334.1
Long-term investments ⁶		1,913.1			1,913.1			2,278.3			1,898.1
Deferred amounts ^2,6		799.9			1,508.9			729.2			1,699.2
Intangible assets ⁶		249.2			249.2			133.9			242.2
Goodwill ⁶		360.5			360.5			31.5			339.6
Accounts payable and other ^1,4,5,6		1,166.9			1,207.1			1,275.9			1,375.8
Current maturities and short-term debt ^5,6		541.2			543.2			703.9			715.2
Current portion of non-recourse debt ⁶		84.2			84.2			30.2			71.7
Long-term debt ^4,5,6		6,166.5			6,169.9			6,053.3			6,264.9
Non-recourse long-term debt ⁶		1,674.3			1,674.3			665.2			1,503.5
Other long-term liabilities ⁶		95.8			95.8			151.8			158.5
Future income taxes ^2,4,5,6		830.6			1,536.7			652.3			1,638.9
Non-controlling interests ⁶		682.9			682.9			514.9			689.9
Retained earnings		2,037.9			1,963.3			1,840.9			1,770.3
Contributed Surplus		7.1			—			5.4			—
Additional paid in capital ¹		—			41.0			—			27.3
Foreign currency translation adjustment ⁵		(115.3	)		—			(139.8	)		—
Accumulated other comprehensive loss⁵		—			(65.3	)		—			(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, 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 $709.0 million (2004 — $596.8 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 $391.9 million (2004 — $331.3 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.


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 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 June 30, 2005, Accumulated Other Comprehensive Loss of $65.3 million consists of an accumulated foreign currency translation balance of $94.5 million (2004 – $129.1 million) and net unrealized gains of $29.2 million (2004 – losses of $18.0 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 $65.3 million (2004 — $147.1 million), the Company estimates that approximately $14.5 million (2004 — $11.8 million), representing unrecognized net losses on derivative activities at June 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 FIN46 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 June 30, 2005. The impact of FIN 46R included in the U.S. GAAP amounts for the three and six months ended June 30, 2004 and at December 31, 2004 is outlined below:


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			Six months ended
(millions of Canadian dollars)	June 30, 2004			June 30, 2004

Transportation revenue		62.1			121.5
Operating and administrative		(16.9	)		(31.3	)
Depreciation		(17.9	)		(35.4	)
Investment and other income		(1.5	)		(3.0	)
Interest expense		(15.1	)		(30.3	)
Income taxes		0.2			0.2

		10.9			21.7
Elimination of EIF investment income		(10.9	)		(21.7	)

Net earnings impact	*nil*			*nil*


Statement of Cash Flows	Three months ended			Six months ended
(millions of Canadian dollars)	June 30, 2004			June 30, 2004
Operating activities		(0.7	)		27.9
Investing activities		(2.2	)		(3.2	)
Financing activities		(24.1	)		(39.6	)

Net cashflow impact		(27.0	)		(14.9	)

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						Six months ended
	June 30,						June 30,
(millions of dollars except per share amounts)	2005			2004			2005			2004

Earnings under U.S. GAAP
As reported		93.6			248.8			310.2			360.8
Stock-based compensation expense		(2.9	)		(2.2	)		(8.3	)		(4.0	)
Included as an expense in the statement of earnings		2.2			1.2			7.9			2.0

Pro forma		92.9			247.8			309.8			358.8
Earnings per common share
As reported		0.28			0.74			0.92			1.08
Stock-based compensation expense		—			0.01			—			0.01

Pro forma		0.28			0.73			0.92			1.07
Diluted earnings per common share
As reported		0.28			0.73			0.91			1.07
Stock-based compensation expense		—			0.01			—			0.01

Pro forma		0.28			0.72			0.91			1.06