Edgar Filing: ENBRIDGE INC

e6vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

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

Dated November 7, 2007

Commission file number 001-15254

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)


Canada		None
(State or other jurisdiction		(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 if the Registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Yes o No þ

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by regulation S-T Rule 101(b)(7):

Yes o No 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

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

N/A

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436) AND FORM F-3 (FILE NO. 333-89618) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following documents are being submitted herewith:

•		Press Release dated November 7, 2007.

•		Interim Report to Shareholders for the nine months ended September 30, 2007.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	ENBRIDGE INC. (Registrant)
Date: November 7, 2007	By:	/s/“Alison T. Love”
		Alison T. Love
		Vice President & Corporate Secretary

NEWS RELEASE

Enbridge reports third quarter earnings of $78.1 million

Highlights

	•		Nine month earnings of $451.6 million increased from $444.3 million in the prior year

	•		Nine month adjusted operating earnings increased 4% to $437.9 million

	•		Third quarter earnings decreased 18% to $78.1 million; and adjusted operating earnings decreased 14% to $79.0 million

	•		Construction activities continue on Southern Access Expansion, Southern Lights Pipeline, Waupisoo Pipeline, the Line 4 Extension and Ontario Wind Project

	•		Enbridge entered an agreement to develop pipeline and terminal facilities for Phase 1 and subsequent phases of the Fort Hills oil sands project at a preliminary cost estimate for the initial facilities of $2 billion

CALGARY, Alberta, November 7, 2007 — “Earnings for the nine months ended September 30, 2007 increased from the prior year and met our expectations,” said Patrick D. Daniel, President and Chief Executive Officer. “Despite the impact of a weaker U.S. dollar and producer start-up delays on our Long Lake and Surmont lateral facilities, we expect to be within our previously communicated full year guidance of $1.75 to $1.85 adjusted operating earnings per share, most likely within the lower half of the range.

“The Company is well into the construction phase on many of the new pipeline projects which we have characterized as the first wave of growth. These pipelines are expected to come into service, and start generating positive cash flows, from mid-2008 through 2010. After that, we see another wave of potential pipeline projects, including the recently announced Fort Hills Pipeline, and we intend to work hard to win that business.”

On November 6, 2007, the Enbridge Board of Directors declared quarterly dividends of $0.3075 per common share and $0.34375 per Series A Preferred Share. Both dividends are payable on December 1, 2007 to shareholders of record on November 15, 2007.

The Board of Directors announced the appointment of Catherine L. Williams as a director of the Company, effective November 1, 2007. Ms. Williams has extensive business and finance experience, most recently with Shell Canada Ltd., where she was Chief Financial Officer.

-1-

Consolidated Earnings


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


Liquids Pipelines		62.4			68.1			197.1			203.0
Gas Pipelines		11.9			15.1			51.0			47.0
Sponsored Investments		21.4			21.9			72.6			65.3
Gas Distribution and Services		(24.7	)		(11.4	)		108.4			108.6
International		22.6			21.1			68.6			64.2
Corporate		(15.5	)		(19.3	)		(46.1	)		(43.8	)

		78.1			95.5			451.6			444.3

Earnings applicable to common shareholders were $78.1 million for the three months ended September 30, 2007, or $0.22 per share, compared with $95.5 million, or $0.28 per share, in 2006. Earnings decreased primarily because of a lower contribution from Aux Sable, a natural gas liquids extraction and fractionation plant, as well as the impact of a weaker U.S. dollar.

Earnings applicable to common shareholders were $451.6 million for the nine months ended September 30, 2007, or $1.27 per share, compared with $444.3 million, or $1.31 per share, in 2006. Earnings per share in 2007 reflected the dilutive effect of the issuance of 15 million common shares in February 2007. While earnings for the nine month period were consistent with the prior year, there were a number of offsetting factors.

Factors increasing earnings included:

	•		Colder than normal weather at Enbridge Gas Distribution (EGD) during 2007 compared with 2006, which was significantly warmer than normal.

	•		Receipt of insurance proceeds in Enbridge Offshore Pipelines (Offshore).

	•		A dilution gain from Enbridge Energy Partners’ (EEP) issuance of partnership units in the second quarter of 2007.

Factors decreasing earnings included:

	•		Reductions in federal future income tax rates in the second quarter of both years. However, the reduction was higher in 2006 and therefore the benefit in 2006 was much larger.

	•		Aux Sable derivative losses in 2007 while 2006 was unhedged.

	•		Increased operating costs in the Enbridge and Athabasca Systems.

	•		The weakened U.S. dollar which reduced earnings by about $5.0 million in the third quarter, primarily in the Gas Pipelines segment and EEP.

Earnings from the Company’s foreign currency denominated investments were lower in 2007 compared with 2006. These earnings are primarily denominated in U.S. dollars as well as Euro earnings from Compañia Logistica de Hidrocarburos CLH, S.A. (CLH). To manage its foreign currency risk, the Company has entered into long-term derivative contracts to hedge the carrying values of these investments. These derivative contracts are accounted for as net investment hedges and, to the extent that they are effective in offsetting the impact of changes in exchange rates on the carrying values of these investments, the derivative contracts are revalued through other comprehensive income. Cash settlements on these derivative contracts are recognized through the balance sheet and do not impact earnings. During the nine months ended September 30, 2007, the Company received foreign currency denominated cash distributions and settled associated hedge transactions resulting in a $12.5 million (2006 — $9.7 million) after-tax cash benefit related to hedging, which was not included in earnings.

-2-

Adjusted Operating Earnings


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars, except per share amounts)	2007			2006			2007			2006


GAAP earnings as reported		78.1			95.5			451.6			444.3
Significant after-tax non-operating factors and variances:
Gas Pipelines
Offshore property insurance recovery from 2005 hurricanes		—			—			(5.3	)		—
Sponsored Investments
Dilution gain on EEP Class A unit issuance		—			—			(11.8	)		—
EEP unrealized derivative fair value losses/(gains)¹		0.5			(2.7	)		2.1			(5.1	)
Revalue future income taxes due to tax rate changes		—			—			0.3			(6.0	)
Gas Distribution and Services
Warmer/(colder) than normal weather affecting EGD		—			(0.5	)		(11.2	)		30.2
Energy Services unrealized derivative fair value losses/(gains)¹		(0.6	)		—			3.9			—
Aux Sable unrealized derivative fair value losses ¹		1.0			—			12.1			—
Revalue future income taxes due to tax rate changes		—			—			(3.8	)		(28.9	)
Corporate
Revalue future income taxes due to tax rate changes		—			—			—			(14.0	)

Adjusted Operating Earnings		79.0			92.3			437.9			420.5

Adjusted Operating Earnings per Common Share		0.22			0.27			1.23			1.24


^1.		The unrealized derivative fair value gains and losses resulted from derivative instruments which are economically effective hedges but do not qualify for hedge accounting treatment.

Adjusted operating earnings for the three months ended September 30, 2007 decreased by $13.3 million primarily due to a lower contribution from Aux Sable and the impact of a weaker U.S. dollar.

The $17.4 million increase in adjusted operating earnings for the nine months ended September 30, 2007 was largely due to:

	•		Improved operating margins and customer growth at EGD.

	•		Lower interest expense in the Corporate segment.

	•		The Company’s increased ownership interest in EEP.

	•		Stronger performance from Olympic and Spearhead pipelines.

These increases were partially offset by:

	•		Aux Sable derivative losses realized in earnings.

	•		Increased costs within the Enbridge and Athabasca Systems.

Non-GAAP Measures

This news release contains references to adjusted operating earnings, which represent earnings applicable to common shareholders adjusted for non-operating factors. Management believes that the presentation of adjusted operating earnings provides useful information to investors and shareholders as it provides increased predictive value. Management uses adjusted operating earnings to set targets and assess performance of the Company. Also, the Company’s dividend payout target is based on adjusted operating earnings. Adjusted operating earnings 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 with a similar measure presented by other issuers.

-3-

Liquids Pipelines

Three months ended

Nine months ended

September 30,

(millions of Canadian dollars)

2007

2006

2007

2006

Enbridge System

46.4

49.0

140.6

149.9

Athabasca System

10.8

14.0

37.4

40.1

Olympic Pipeline

2.5

2.2

7.7

4.8

Spearhead Pipeline

1.6

0.4

6.0

3.1

Feeder Pipelines and Other

1.1

2.5

5.4

5.1

62.4

68.1

197.1

203.0

•		Enbridge System earnings decreased from the prior year due to the impact of a strong labour market on compensation expense, higher pipeline integrity costs and increased taxes in the Terrace component, partially offset by lower oil loss costs.

•		Athabasca System earnings decreased from the prior year due to higher property taxes and the costs of minor leak remediation in 2007.

•		Olympic Pipeline was acquired on February 1, 2006. Earnings for 2007 reflected a full nine months of operations as well as higher tolls in 2007 to compensate for under shipments in 2006. Olympic’s cost of service tolling methodology requires annual toll adjustments for over or under collections in prior years.

•		Spearhead Pipeline commenced operations in early March 2006. Earnings for 2007 reflected a full nine months of operations as well as increased throughput. The third quarter of 2006 reflected higher operating costs due to timing.

•		Feeder Pipelines and Other earnings in the third quarter of 2007 were reduced by increased business development costs on projects in the early development stage.

Gas Pipelines

Three months ended

Nine months ended

September 30,

(millions of Canadian dollars)

2007

2006

2007

2006

Alliance Pipeline US

6.6

7.8

21.4

22.3

Vector Pipeline

3.8

2.5

10.7

9.3

Enbridge Offshore Pipelines

1.5

4.8

18.9

15.4

11.9

15.1

51.0

47.0

•		Alliance Pipeline US earnings reflected the weaker U.S. dollar in the third quarter of 2007.

•		Vector Pipeline earnings were higher in the third quarter of 2007 due to lower scheduled integrity costs, partly offset by the weaker U.S. dollar in 2007.

•		Enbridge Offshore Pipelines earnings for the nine month period included $11.3 million of insurance proceeds for both property insurance recoveries and business interruption resulting from the 2005 hurricanes. The final insurance claim settlement is expected in late 2007 or early 2008.

•		Enbridge Offshore Pipelines earnings also reflected the impact of a weaker U.S. dollar, continuing repair and inspection costs and expected continuing natural production declines on deliveries to the pipelines in 2007. Start up issues experienced by producers on key production platforms, resulting from the effects of the extreme 2005 hurricane season, continue to delay new sources of volumes.

-4-

Sponsored Investments


	Three months ended				Nine months ended
	September 30,				September 30,
(millions of Canadian dollars)	2007		2006		2007			2006


Enbridge Energy Partners		12.2		12.1		32.6			31.5
Enbridge Income Fund (EIF)		9.2		9.8		28.5			27.8
Dilution gain in EEP		—		—		11.8			—
Revalue future income taxes due to tax changes in EIF		—		—		(0.3	)		6.0

		21.4		21.9		72.6			65.3

•		EEP’s nine month 2007 earnings, after adjusting for unrealized derivative fair value losses, reflected the increase in Enbridge’s ownership interest from 10.9% to 16.6% during the third quarter of 2006. EEP’s earnings increased compared with the prior year as increased throughput on principal natural gas and liquids systems was partially offset by higher operating expenses. Nine month results were also negatively impacted by higher natural gas measurement losses and a processing plant temporary shutdown for maintenance, as well as the impact of a weaker U.S. dollar.

•		EEP issued partnership units in the second quarter of 2007 and, because Enbridge did not fully participate, a dilution gain resulted and Enbridge’s ownership interest decreased from 16.6% to 15.0%.

•		In 2007, EIF recognized future taxes within entities that will become taxable in 2011 as a result of the enactment of Bill C-52 “The Tax Fairness Plan”. This future tax increase was partially offset by the revaluation of future income tax obligations previously recorded as a result of tax rate reductions. The prior year included the impact of larger tax rate reductions.

Gas Distribution and Services


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


Enbridge Gas Distribution		(29.5	)		(27.8	)		74.3			25.4
Noverco		(5.8	)		(3.9	)		10.2			11.2
CustomerWorks/ECS		1.0			5.7			6.5			16.0
Enbridge Gas New Brunswick		3.1			2.8			9.0			7.1
Other Gas Distribution		(0.9	)		(1.2	)		5.2			4.1
Energy Services		3.8			(0.6	)		4.3			3.1
Aux Sable		4.7			14.9			(3.5	)		16.1
Other		(1.1	)		(1.3	)		(1.4	)		(3.3	)
Revalue future income taxes due to tax rate changes		—			—			3.8			28.9

		(24.7	)		(11.4	)		108.4			108.6

•		EGD’s earnings improved from the prior year primarily due to the impact of colder weather. In 2006, weather was significantly warmer than normal, resulting in lower earnings, whereas in 2007 weather has been colder than normal. Earnings also increased because of customer growth and higher operating margins. The third quarter is seasonally warm and therefore fixed costs are typically not covered during this quarter, resulting in losses.

•		CustomerWorks/ECS earnings decreased because, pursuant to an OEB recommendation, CustomerWorks transitioned customer care services related to EGD to a third party service provider.

•		Energy Services earnings, after adjusting for unrealized fair value losses and gains on derivative instruments, were stronger in 2007 due to increased optimization of Enbridge assets, improved market fundamentals for crude oil and increased transportation and storage volumes, all at Tidal Energy. Energy Services includes Gas Services and Tidal Energy. Tidal Energy was included in Other in prior years.

-5-

•

Aux Sable earnings, on a reported basis and after adjusting for unrealized fair value losses on derivative instruments, were lower than 2006 due to risk management activities. The Company has entered into derivative transactions to mitigate the uncertainty of the Company’s share of the contingent upside sharing mechanism which allows Aux Sable to share in natural gas processing margins in excess of certain thresholds. These risk management strategies provide cash flow predictability which is important to the Company in this period of significant project financing. These derivative financial instruments target full year 2007 adjusted operating earnings of approximately $10 million, of which approximately $8.6 million were recorded during the nine month period. Aux Sable earnings were also negatively impacted by the weakened U.S. dollar in 2007.

International


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


CLH		15.3			14.5			46.5			42.5
OCENSA/CITCol		8.1			8.4			24.5			24.7
Other		(0.8	)		(1.8	)		(2.4	)		(3.0	)

		22.6			21.1			68.6			64.2

•

CLH earnings increased due to higher transportation tariffs, higher volumes and the impact of a stronger Euro.

•

Other includes lower business development costs in 2007 due to a de-emphasizing of business development activities in the International segment.

Corporate


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


Corporate		(15.5	)		(19.3	)		(46.1	)		(57.8	)
Revalue future income taxes due to tax rate changes		—			—			—			14.0

		(15.5	)		(19.3	)		(46.1	)		(43.8	)

•

Corporate costs, before the revalue of future income taxes due to tax rate changes, decreased primarily due to decreased interest expense resulting from lower levels of corporate debt during the first half of 2007. Debt was repaid from the proceeds of the $566.4 million issuance of equity on February 2, 2007. Interest expense in Corporate was also lower in the second and third quarters of 2007 because of higher interest capitalization related to projects under construction.

Conference Call

Enbridge will hold a conference call on Wednesday, November 7, 2007 at 9:00 a.m. Eastern time (7:00 a.m. Mountain time) to discuss the third quarter 2007 results. Analysts, members of the media and other interested parties can access the call at 617-213-4863 or toll-free at 1-888-713-4209 using the access code of 32445851. The call will be audio webcast live at www.enbridge.com/investor. A webcast replay will be available approximately two hours after the conclusion of the event and a transcript will be posted to the website within approximately 24 hours. The webcast replay will be available at toll-free 1-888-286-8010 or 617-801-6888. The access code for the replay is 26279289.

The conference call will begin with a presentation by the Company’s Chief Executive Officer and Chief Financial Officer followed by a question and answer period for investment analysts. A question and answer period for members of the media will immediately follow.

-6-

The unaudited interim consolidated financial statements and Management’s Discussion and Analysis, which contain additional notes and disclosures, are available on the Enbridge website.

Enbridge Inc., a Canadian company, is a leader in energy transportation and distribution in North America and internationally. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids pipeline system. The Company also has international operations and a growing involvement in the natural gas transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company, and provides distribution services in Ontario, Quebec, New Brunswick and New York State. Enbridge employs approximately 5,000 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.

In the interest of providing Enbridge shareholders and potential investors with information about the Company and its subsidiaries, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations, certain information provided in this News Release constitutes forward-looking statements or information (collectively, “forward-looking statements”). Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believe” and similar words suggesting future outcomes or statements regarding an outlook. Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, weather, economic conditions, exchange rates, interest rates and commodity prices, including but not limited to those risks and uncertainties discussed in this News Release and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this News Release or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.


Enbridge Contacts:
*Media*		*Investment Community*
Jennifer Varey		Vern Yu
(403) 508-6563		(403) 231-3946
E-mail: jennifer.varey@enbridge.com		E-mail: vern.yu@enbridge.com

-7-

ENBRIDGE INC.
HIGHLIGHTS


	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars, except per share amounts)	2007			2006			2007			2006

Earnings Applicable to Common Shareholders
Liquids Pipelines		62.4			68.1			197.1			203.0
Gas Pipelines		11.9			15.1			51.0			47.0
Sponsored Investments		21.4			21.9			72.6			65.3
Gas Distribution and Services		(24.7	)		(11.4	)		108.4			108.6
International		22.6			21.1			68.6			64.2
Corporate		(15.5	)		(19.3	)		(46.1	)		(43.8	)

		78.1			95.5			451.6			444.3

Cash Flow Data
Cash provided by operating activities before changes in operating assets and liabilities		212.9			230.8			935.3			816.4
Cash provided by/(used in) operating activities		(79.4	)		(33.4	)		1,101.8			1,166.4
Additions to property, plant and equipment		672.6			275.8			1,574.2			676.5
Acquisitions and long-term investments		4.3			291.9			19.7			448.2
Common share dividends		113.1			100.6			338.9			302.0

Per Share Information
Earnings per Common Share		0.22			0.28			1.27			1.31
Diluted Earnings per Common Share		0.22			0.28			1.26			1.30
Dividends per Common Share		0.3075			0.2875			0.9225			0.8625

Shares Outstanding (millions)
Weighted Average Common Shares Outstanding		356.2			340.4			354.7			339.6
Diluted Weighted Average Common Shares Outstanding		359.5			344.5			357.7			342.9

Operating
Liquids Pipelines — Deliveries (thousands of barrels per day)
Enbridge System¹		1,977			2,007			2,001			1,972
Athabasca System²		175			187			165			192
Spearhead Pipeline		91			67			97			70
Olympic Pipeline		285			292			287			294
Gas Pipelines — Average Daily Throughput Volume (millions of cubic feet per day)
Alliance Pipeline US		1,535			1,513			1,606			1,595
Vector Pipeline		974			879			984			1,014
Enbridge Offshore Pipelines		2,201			2,265			2,118			2,190
Gas Distribution and Services³
Volumes (billion cubic feet)		48			45			316			285
Number of active customers (thousands)		1,880			1,829			1,880			1,829
Degree day deficiency⁴
Actual⁵		45			85			2,439			2,190
Forecast based on normal weather		92			58			2,380			2,498


^1.		Enbridge System includes Canadian mainline deliveries in Western Canada and to the Lakehead System at the U.S. border, as well as Line 8 and Line 9 in Eastern Canada.

^2.		Volumes are for the Athabasca mainline only and do not include laterals included in the Athabasca System.

^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 which is indicative of volumetric requirements of natural gas utilized for heating purposes. 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 Greater Toronto Area.

^5.		Given that degree days are largely ineffective during the non-heating season, there was no measurable impact on earnings in the third quarter. Degree days are fully effective, typically in the peak winter months, when their occurrence directly impacts the consumption pattern by a similar magnitude.

-8-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars, except per share amounts)	2007			2006			2007			2006


Revenues
Commodity sales		2,124.8			1,645.0			6,972.4			6,141.5
Transportation		456.4			453.5			1,541.4			1,515.7
Energy services		52.8			86.4			207.1			201.6

		2,634.0			2,184.9			8,720.9			7,858.8

Expenses
Commodity costs		2,004.6			1,562.4			6,583.4			5,850.0
Operating and administrative		290.0			256.6			844.9			759.9
Depreciation and amortization		151.0			145.4			450.0			437.6

		2,445.6			1,964.4			7,878.3			7,047.5

		188.4			220.5			842.6			811.3
Income from Equity Investments		31.4			35.9			111.8			134.0
Other Investment Income		24.9			33.2			133.5			83.4
Interest Expense		(135.6	)		(142.2	)		(409.4	)		(417.3	)

		109.1			147.4			678.5			611.4
Non-Controlling Interests		(9.7	)		(13.4	)		(34.7	)		(46.6	)

		99.4			134.0			643.8			564.8
Income Taxes		(19.6	)		(36.8	)		(187.1	)		(115.4	)

Earnings		79.8			97.2			456.7			449.4
Preferred Share Dividends		(1.7	)		(1.7	)		(5.1	)		(5.1	)

Earnings Applicable to Common Shareholders		78.1			95.5			451.6			444.3


Earnings Per Common Share		0.22			0.28			1.27			1.31


Diluted Earnings Per Common Share		0.22			0.28			1.26			1.30

-9-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three months ended						Nine months ended
	September 30,						September 30,

(unaudited; millions of Canadian dollars)	2007			2006			2007			2006

Earnings		79.8			97.2			456.7			449.4
Other Comprehensive Income/(Loss) Change in unrealized gains on cash flow hedges, net of tax		17.6			—			59.1			—
Reclassification to earnings of realized cash flow hedges, net of tax		(8.1	)		—			8.8			—
Other comprehensive gain/(loss) from equity investees		0.5			—			(4.5	)		—
Non-Controlling interest in other comprehensive income		(1.8	)		—			1.2			—
Change in foreign currency translation adjustment		(164.8	)		(5.4	)		(443.5	)		(89.3	)
Change in unrealized gains on net investment hedges, net of tax		66.7			13.1			166.8			43.6

Comprehensive Income		(10.1	)		104.9			244.6			403.7

-10-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY



	Nine months ended
	September 30,

(unaudited; millions of Canadian dollars)	2007			2006


Preferred Shares		125.0			125.0


Common Shares
Balance at beginning of period		2,416.1			2,343.8
Common shares issued		566.4			—
Dividend reinvestment and share purchase plan		13.9			14.0
Shares issued on exercise of stock options		21.4			41.9

Balance at End of Period		3,017.8			2,399.7


Contributed Surplus
Balance at beginning of period		18.3			10.0
Stock-based compensation		8.1			5.8
Option exercises		(1.2	)		(1.8	)

Balance at End of Period		25.2			14.0


Retained Earnings
Balance at beginning of period		2,322.7			2,098.2
Earnings applicable to common shareholders		451.6			444.3
Cumulative impact of change in accounting policy (Note 1)		(47.0	)		—
Common share dividends		(338.9	)		(302.0	)
Dividends paid to reciprocal shareholder		10.3			9.1

Balance at End of Period		2,398.7			2,249.6


Accumulated Other Comprehensive Loss
Balance at beginning of period		(135.8	)		(171.8	)
Cumulative impact of change in accounting policy (Note 1)		48.2			—
Other comprehensive loss (Note 1)		(212.1	)		(45.7	)

Balance at End of Period		(299.7	)		(217.5	)


Reciprocal Shareholding
Balance at beginning of period		(135.7	)		(135.7	)
Participation in common shares issued		(18.6	)		—

Balance at End of Period		(154.3	)		(135.7	)

Total Shareholders’ Equity		5,112.7			4,435.1

-11-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three months ended						Nine months ended
	September 30,						September 30,

(unaudited; millions of Canadian dollars)	2007			2006			2007			2006


Cash Provided By Operating Activities
Earnings		79.8			97.2			456.7			449.4
Depreciation and amortization		151.0			145.4			450.0			437.6
Unrealized losses on derivative instruments		10.5			—			24.0			—
Equity earnings in excess of cash distributions		(14.2	)		(20.2	)		(42.1	)		(63.0	)
Gain on reduction of ownership interest		—			—			(33.9	)		—
Future income taxes		(36.8	)		(4.6	)		34.5			(52.7	)
Other		22.6			12.9			46.1			45.1
Changes in operating assets and liabilities		(292.3	)		(264.2	)		166.5			350.0

		(79.4	)		(33.5	)		1,101.8			1,166.4

Investing Activities
Acquisitions		—			—			—			(101.4	)
Long-term investments		(4.3	)		(291.9	)		(19.7	)		(346.8	)
Additions to property, plant and equipment		(672.6	)		(275.7	)		(1,574.2	)		(676.5	)
Affiliate loans		—			—			—			28.0
Change in construction payable		57.2			0.8			60.9			(13.5	)

		(619.7	)		(566.8	)		(1,533.0	)		(1,110.2	)

Financing Activities
Net change in short-term borrowings and short-term debt		811.7			456.7			(298.7	)		(96.5	)
Net change in non-recourse short-term debt		11.7			(9.7	)		18.9			(5.2	)
Long-term debt issues		—			300.0			1,156.6			800.0
Long-term debt repayments		(100.0	)		—			(634.5	)		(400.0	)
Non-recourse long-term debt issues		—			—			14.4			2.8
Non-recourse long-term debt repayments		(2.9	)		—			(31.6	)		(29.7	)
Contributions from/(distributions to) non-controlling interests		0.8			(5.5	)		(11.9	)		(25.4	)
Common shares issued		7.0			10.5			593.2			49.0
Preferred share dividends		(1.7	)		(1.7	)		(5.1	)		(5.1	)
Common share dividends		(113.1	)		(100.6	)		(338.9	)		(302.0	)

		613.5			649.7			462.4			(12.1	)

Increase/(Decrease) in Cash and Cash Equivalents		(85.6	)		49.4			31.2			44.1
Cash and Cash Equivalents at Beginning of Period		256.5			148.6			139.7			153.9

Cash and Cash Equivalents at End of Period		170.9			198.0			170.9			198.0

-12-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION



	September 30,			December 31,
(unaudited; millions of Canadian dollars)	2007			2006


Assets
Current Assets
Cash and cash equivalents		170.9			139.7
Accounts receivable and other		2,046.7			2,045.6
Inventory		867.0			868.9

		3,084.6			3,054.2
Property, Plant and Equipment, net		12,037.0			11,264.7
Long-Term Investments		2,098.2			2,299.4
Deferred Amounts and Other Assets		1,063.7			924.5
Intangible Assets		215.4			241.5
Goodwill		381.7			394.9
Future Income Taxes		210.2			200.1

		19,090.8			18,379.3


Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings		570.8			807.9
Accounts payable and other		2,022.0			1,723.8
Interest payable		98.8			95.1
Current maturities and short-term debt		452.7			537.0
Current portion of non-recourse debt		56.8			60.1

		3,201.1			3,223.9
Long-Term Debt		7,295.7			7,054.0
Non-Recourse Long-Term Debt		1,520.9			1,622.0
Other Long-Term Liabilities		278.3			91.1
Future Income Taxes		1,030.0			1,062.5
Non-Controlling Interests		652.1			715.2

		13,978.1			13,768.7

Shareholders’ Equity
Share capital
Preferred shares		125.0			125.0
Common shares		3,017.8			2,416.1
Contributed surplus		25.2			18.3
Retained earnings		2,398.7			2,322.7
Accumulated other comprehensive loss		(299.7	)		(135.8	)
Reciprocal shareholding		(154.3	)		(135.7	)

		5,112.7			4,610.6

		19,090.8			18,379.3

-13-

SEGMENTED INFORMATION

Three months ended September 30, 2007

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services

International

Corporate

Consolidated

Revenues

266.7

76.3

65.0

2,224.1

1.9

—

2,634.0

Commodity costs

—

(2,004.6

)

—

(2,004.6

)

Operating and administrative

(110.0

)

(23.6

)

(19.4

)

(129.7

)

(3.2

)

(4.1

)

(290.0

)

Depreciation and amortization

(39.6

)

(20.0

)

(17.8

)

(71.4

)

(0.2

)

(2.0

)

(151.0

)

117.1

32.7

27.8

18.4

(1.5

)

(6.1

)

188.4

Income from equity investments

(0.3

)

—

28.0

(11.5

)

15.6

(0.4

)

31.4

Other investment income

4.0

1.2

1.0

5.2

9.0

4.5

24.9

Interest and preferred share dividends

(27.3

)

(15.9

)

(15.4

)

(51.5

)

—

(27.2

)

(137.3

)

Non-controlling interests

(0.4

)

—

(7.7

)

(1.6

)

—

(9.7

)

Income taxes

(30.7

)

(6.1

)

(12.3

)

16.3

(0.5

)

13.7

(19.6

)

Earnings applicable to common shareholders

62.4

11.9

21.4

(24.7

)

22.6

(15.5

)

78.1


Three months ended September 30, 2006
										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of Canadian dollars)	Pipelines			Pipelines			Investments			and Services			International			Corporate			Consolidated

Revenues		254.7			87.2			60.8			1,778.4			3.8			—			2,184.9
Commodity costs		—			—			—			(1,562.4	)		—			—			(1,562.4	)
Operating and administrative		(93.7	)		(24.6	)		(13.4	)		(113.5	)		(4.7	)		(6.7	)		(256.6	)
Depreciation and amortization		(35.8	)		(23.5	)		(17.5	)		(66.7	)		(0.3	)		(1.6	)		(145.4	)

		125.2			39.1			29.9			35.8			(1.2	)		(8.3	)		220.5
Income from equity investments		0.2			—			31.1			(9.3	)		13.9			—			35.9
Other investment income		1.9			2.3			0.4			4.9			9.9			13.8			33.2
Interest and preferred share dividends		(24.8	)		(18.0	)		(14.7	)		(48.9	)		—			(37.5	)		(143.9	)
Non-controlling interests		(0.5	)		—			(11.3	)		(1.6	)		—			—			(13.4	)
Income taxes		(33.9	)		(8.3	)		(13.5	)		7.7			(1.5	)		12.7			(36.8	)

Earnings applicable to common shareholders		68.1			15.1			21.9			(11.4	)		21.1			(19.3	)		95.5

-14-

Nine months ended September 30, 2007

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services

International

Corporate

Consolidated

Revenues

798.6

241.4

197.8

7,476.3

6.8

—

8,720.9

Commodity costs

—

(6,583.4

)

—

(6,583.4

)

Operating and administrative

(312.4

)

(64.7

)

(56.7

)

(388.7

)

(10.4

)

(12.0

)

(844.9

)

Depreciation and amortization

(117.5

)

(64.3

)

(55.9

)

(207.5

)

(0.7

)

(4.1

)

(450.0

)

368.7

112.4

85.2

296.7

(4.3

)

(16.1

)

842.6

Income from equity investments

(0.7

)

—

72.2

(3.5

)

44.8

(1.0

)

111.8

Other investment income

7.7

18.3

37.8

13.3

30.1

26.3

133.5

Interest and preferred share dividends

(77.1

)

(50.1

)

(45.9

)

(152.0

)

—

(89.4

)

(414.5

)

Non-controlling interests

(1.1

)

—

(28.8

)

(4.8

)

—

(34.7

)

Income taxes

(100.4

)

(29.6

)

(47.9

)

(41.3

)

(2.0

)

34.1

(187.1

)

Earnings applicable to common shareholders

197.1

51.0

72.6

108.4

68.6

(46.1

)

451.6


Nine months ended September 30, 2006
										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of Canadian dollars)	Pipelines			Pipelines			Investments			and Services			International			Corporate			Consolidated

Revenues		748.6			260.3			186.2			6,654.6			9.1			—			7,858.8
Commodity costs		—			—			—			(5,850.0	)		—			—			(5,850.0	)
Operating and administrative		(263.7	)		(71.7	)		(46.3	)		(352.4	)		(12.5	)		(13.3	)		(759.9	)
Depreciation and amortization		(114.5	)		(65.9	)		(53.5	)		(198.8	)		(0.7	)		(4.2	)		(437.6	)

		370.4			122.7			86.4			253.4			(4.1	)		(17.5	)		811.3
Income from equity investments		0.1			—			85.3			8.3			40.3			—			134.0
Other investment income		2.9			8.3			2.1			15.3			35.6			19.2			83.4
Interest and preferred share dividends		(75.6	)		(55.3	)		(44.7	)		(143.7	)		—			(103.1	)		(422.4	)
Non-controlling interests		(1.4	)		—			(41.3	)		(3.9	)		—			—			(46.6	)
Income taxes		(93.4	)		(28.7	)		(22.5	)		(20.8	)		(7.6	)		57.6			(115.4	)

Earnings applicable to common shareholders		203.0			47.0			65.3			108.6			64.2			(43.8	)		444.3

-15-

Enbridge Inc.
Management’s Discussion & Analysis
For the Three and Nine Months Ended September 30, 2007

Dated November 6, 2007

This Management’s Discussion and Analysis (MD&A) should be read in conjunction with the unaudited consolidated financial statements of Enbridge Inc. (Enbridge or the Company) as at and for the three and nine months ended September 30, 2007. It should also be read in conjunction with the audited consolidated financial statements and MD&A included in the Company’s Annual Report for the year ended December 31, 2006. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com .

Consolidated Earnings


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


Liquids Pipelines		62.4			68.1			197.1			203.0
Gas Pipelines		11.9			15.1			51.0			47.0
Sponsored Investments		21.4			21.9			72.6			65.3
Gas Distribution and Services		(24.7	)		(11.4	)		108.4			108.6
International		22.6			21.1			68.6			64.2
Corporate		(15.5	)		(19.3	)		(46.1	)		(43.8	)

		78.1			95.5			451.6			444.3

Earnings applicable to common shareholders were $451.6 million for the nine months ended September 30, 2007, or $1.27 per share, compared with $444.3 million or $1.31 per share in 2006. Earnings per share in 2007 reflected the dilutive effect of the issuance of 15 million common shares in February 2007. Earnings for the nine month period were consistent with the prior year but reflected offsetting factors within the Company’s business segments.

Factors increasing earnings included:

	•		Colder than normal weather at Enbridge Gas Distribution (EGD) during 2007 compared with 2006, which was significantly warmer than normal.

	•		Receipt of insurance proceeds in Enbridge Offshore Pipelines (Offshore).

	•		A dilution gain from Enbridge Energy Partners’ (EEP) issuance of partnership units in the second quarter of 2007.

Factors decreasing earnings included:

	•		Reductions in federal future income tax rates in the second quarter of both years. However, the reduction was higher in 2006 and therefore the benefit in 2006 was much larger.

	•		Aux Sable derivative losses in 2007 while 2006 was unhedged.

	•		Increased operating costs in the Enbridge and Athabasca Systems.

	•		The weakened U.S. dollar which reduced earnings by about $5.0 million in the third quarter primarily in the Gas Pipelines segment and EEP.

Earnings applicable to common shareholders were $78.1 million for the three months ended September 30, 2007, or $0.22 per share, compared with $95.5 million, or $0.28 per share in 2006. Earnings decreased primarily because of a lower contribution from Aux Sable, a natural gas liquids extraction and fractionation plant, as well as the impact of a weaker U.S. dollar.

-1-

FORWARD LOOKING INFORMATION

In the interest of providing Enbridge shareholders and potential investors with information about the Company and its subsidiaries, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations, certain information provided in this Management’s Discussion and Analysis (MD&A) constitutes forward-looking statements or information (collectively, “forward-looking statements”). Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believe” and similar words suggesting future outcomes or statements regarding an outlook. Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, weather, economic conditions, exchange rates, interest rates and commodity prices, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

-2-

ADJUSTED OPERATING EARNINGS


	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars, except per share amounts)	2007			2006			2007			2006


GAAP earnings as reported		78.1			95.5			451.6			444.3
Significant after-tax non-operating factors and variances:
Gas Pipelines
Offshore property insurance recovery from 2005 hurricanes		—			—			(5.3	)		—
Sponsored Investments
Dilution gain on EEP Class A unit issuance		—			—			(11.8	)		—
EEP unrealized derivative fair value losses/(gains)¹		0.5			(2.7	)		2.1			(5.1	)
Revalue future income taxes due to tax rate changes		—			—			0.3			(6.0	)
Gas Distribution and Services
Warmer/(colder) than normal weather affecting EGD		—			(0.5	)		(11.2	)		30.2
Energy Services unrealized derivative fair value losses/(gains)¹		(0.6	)		—			3.9			—
Aux Sable unrealized derivative fair value losses¹		1.0			—			12.1			—
Revalue future income taxes due to tax rate changes		—			—			(3.8	)		(28.9	)
Corporate
Revalue future income taxes due to tax rate changes		—			—			—			(14.0	)

Adjusted Operating Earnings		79.0			92.3			437.9			420.5

Adjusted Operating Earnings per Common Share		0.22			0.27			1.23			1.24


¹		The unrealized derivative fair value gains and losses resulted from derivative instruments which are economically effective hedges but do not qualify for hedge accounting treatment.

The increase in adjusted operating earnings of $17.4 million for the nine months ended September 30, 2007 was largely due to:

	•	Improved operating margins and customer growth at EGD.
	•	Lower interest expense in the Corporate Segment.
	•	The Company’s increased ownership interest in EEP.
	•	Stronger performance from Olympic and Spearhead pipelines.

The increase was partially offset by:

	•	Aux Sable derivative losses realized in earnings.
	•	Increased costs within the Enbridge and Athabasca Systems.

Although the same factors which increased adjusted operating earnings for the nine months ended September 30, 2007 also increased earnings during the quarter, quarterly adjusted operating earnings were lower than the prior year by $13.3 million primarily due to a lower contribution from Aux Sable and the impact of a weaker U.S. dollar.

Non-GAAP Measures
This MD&A contains references to adjusted operating earnings, which represent earnings applicable to common shareholders adjusted for non-operating factors. Management believes that the presentation of adjusted operating earnings provides useful information to investors and shareholders as it provides increased predictive value. Management uses adjusted operating earnings to set targets and assess performance of the Company. Also, the Company’s dividend payout target is based on adjusted operating earnings. Adjusted operating earnings 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 with a similar measure presented by other issuers.

-3-

RECENT DEVELOPMENTS

Liquids Pipelines

Growth projects within Liquids Pipelines are driven by oil sands fundamentals and are organized into five separate platforms including mainline capacity expansion, upstream pipeline development within Alberta, new market access, diluent supply projects and terminalling and tankage infrastructure. Progress on the projects within each of the platforms in 2007 is as follows:

Mainline Capacity Expansion

The Company is expanding the mainline system, both in Canada and the United States, through the Southern Access Mainline Expansion expected to be completed in 2009 and through the Alberta Clipper Project expected to be completed and in service in mid-2010. A smaller, debottlenecking project between Edmonton and Hardisty, the Line 4 Extension Project, is expected to be completed in early 2009.

Southern Access Mainline Expansion

Following the approval of tolling principles by the Federal Energy Regulatory Commission (FERC) and the National Energy Board (NEB) in 2006, construction activities are underway on the 321 mile section from Superior to Delavan, Wisconsin with over 65% of welding completed. The expansion will be completed in stages, finishing in 2009.

Based on construction costs experienced on the initial phase of the project, the expected cost of the project has been updated to an estimated US$2.4 billion (Enbridge — $0.3 billion, EEP — US$2.1 billion). Tolls on the Canadian Mainline will be fully adjusted for the actual capital cost of the expansion, while tolls on the U.S. Mainline, held by EEP, will be adjusted for 88% of the actual cost.

Alberta Clipper Project

In the second quarter of 2007, Enbridge filed an application with the NEB to construct a new 36-inch diameter, 1,607 kilometre (1,000 mile) crude oil pipeline from Hardisty, Alberta to Superior, Wisconsin generally within or alongside Enbridge’s existing right-of-way. The application includes a commercial supplement which sets out the tolling principles and risk and return parameters agreed to with shippers. Enbridge’s affiliate, EEP, finalized commercial terms with shippers and plans to file a similar application and set of toll principles with the FERC for the United States portion of the Alberta Clipper project. Subject to regulatory approval, Enbridge anticipates bringing Alberta Clipper into service in mid-2010. The project will have an initial capacity of 450,000 barrels per day (bpd), is expandable to 800,000 bpd and will form part of the existing Enbridge System in Canada and the EEP Lakehead System in the United States.

The Canadian segment of the line is expected to cost $2.0 billion (2007 dollars, excluding allowance for funds used during construction) and the U.S. segment, to be undertaken by EEP, is expected to cost US$1.0 billion (2007 dollars, excluding capitalized interest). Increased cost estimates are primarily a result of a shortage of skilled labour. In addition, detailed environmental and engineering studies have been completed and are reflected in the revised cost estimate.

Line 4 Extension Project

In the second quarter of 2007, Enbridge filed a regulatory application with the NEB for the construction and operation of the $0.3 billion Line 4 Extension project. Subject to regulatory approvals, the project, involving construction of 136 kilometres (85 miles) of 36-inch diameter pipe on the mainline system between Edmonton, Alberta and Hardisty, Alberta, is expected to be in service in early 2009. Procurement of long lead items was completed in September and detailed engineering for the pipeline and stations is proceeding.

-4-

Upstream Pipeline Development

Significant new infrastructure upstream of the mainline system is being developed to support the Alberta oil sands, including construction of the Waupisoo Pipeline, expansion of the Athabasca Pipeline and the establishment of agreements with Fort Hills Energy, L.P. to develop pipeline and terminaling facilities for the Fort Hills oil sands project.

Waupisoo Pipeline

The 30-inch diameter crude oil pipeline from the Cheecham terminal on the Athabasca Pipeline to Edmonton, Alberta received approval from the Alberta Energy and Utilities Board in February 2007. Capital costs for the project are currently expected to approximate $0.6 billion. Capital cost risks are shared between the Company and shippers. Approximately 45% of the pipeline has been installed and the project remains on schedule for completion in mid-2008.

Athabasca Pipeline

Enbridge has agreements to provide pipeline transportation services on the Athabasca Pipeline for the Long Lake and Surmont Oil Sands Projects. The construction of the laterals and facilities at Long Lake was completed in the first half of 2007 and these facilities are expected to be in service in late 2007 to coincide with the first production from the Long Lake Project. The Company completed construction of the Surmont facilities and has placed them into service.

In late April 2007, the construction and commissioning of the Athabasca Pipeline expansion projects were completed. These projects included the addition of pumping stations at Elk Point and Cheecham, as well as modifications to existing pumping stations. The Elk point expansion is in-service and the Cheecham expansion is awaiting production from the Long Lake Oil Sands Project.

Fort Hills Pipeline System

The Company announced that it has entered into an agreement with Fort Hills Energy, L.P. to develop pipeline and terminaling facilities to meet the requirements of Phase 1 and subsequent phases of the Fort Hills oil sands project. The preliminary plan for the Fort Hills Pipeline System includes a pipeline from the mine site north of Fort McMurray, Alberta to the upgrader site northeast of Edmonton, Alberta with a capacity of 250,000 bpd of diluted bitumen. The system will also consist of a 70,000 bpd diluent pipeline, terminaling facilities at the mine site and the upgrader, and interconnecting pipelines linking the upgrader to the Edmonton pipeline hub. The estimated cost of the initial pipeline system and related facilities is approximately $2 billion, subject to finalization of scope and estimate refinement, with planned in-service dates in mid-2011. Construction of the Fort Hills Project and the associated pipeline facilities are subject to final approvals by the Fort Hills’ partners and various regulatory approvals and permits.

New Market Access

The Company is developing new options for expanding market access for crude oil through extending the mainline system; expanding the Spearhead Pipeline from Chicago to Cushing; developing access to the U.S. Gulf Coast market; and developing access to Asian and Californian markets with the Gateway Project.

Southern Access Extension Project

This project is now estimated to cost US$0.5 billion and involves the construction of a new 36-inch diameter, 400,000 bpd pipeline extending the mainline from Flanagan, Illinois to Patoka, Illinois. The revised tolling methodology application for the Southern Access Extension Project was filed with the FERC on October 18, 2007. Tolls will be fully adjusted for the actual capital cost of the project. Subject to regulatory approval, construction would begin in 2008 with an estimated in-service date of 2009.

Spearhead Pipeline Expansion

The Company successfully completed the Spearhead Pipeline Expansion Open Season in the second quarter of 2007. The expansion, to be effected through additional pumping stations, is expected to cost

-5-

US$0.1 billion and will increase capacity from Chicago, Illinois to Cushing, Oklahoma by 65,000 bpd to 190,000 bpd. Of the 65,000 bpd increased capacity, 30,000 bpd was committed to new shippers. The remaining 35,000 bpd capacity is available for spot shippers unless the committed shippers exercise their preferential right to 30,000 bpd of this capacity. Preliminary engineering design has been completed. The expansion is expected to be completed in early 2009.

United States Gulf Coast Initiative

During the second quarter of 2007, Enbridge and ExxonMobil announced that they are jointly pursuing the potential for a crude oil pipeline from Patoka, Illinois to Beaumont, Texas and onward to Houston, Texas. This pipeline project is in the initial stages as Enbridge and ExxonMobil are in discussions with potential shippers regarding scope and timing of the project. This project could be in-service by the end of 2010 depending on shipper preferences.

The Gateway Project

The Gateway Project includes a crude oil export line from the Edmonton, Alberta area to Kitimat, British Columbia and a condensate import line from Kitimat to the Edmonton area. Subject to commercial support, regulatory and other approvals, the Company estimates the in-service date will be in the 2012 — 2014 timeframe.

Diluent Supply Projects

In response to the increased demand for diluent driven by increasing heavy oil production in Alberta, the Company is developing the Southern Lights Pipeline Project which will bring diluent to Alberta from the U.S. Midwest.

Southern Lights Pipeline

During the first quarter of 2007, Enbridge filed for regulatory approval of the Canadian portion of the 180,000 bpd Southern Lights diluent pipeline project with the NEB, having obtained long-term commitments from shippers in 2006. In the fourth quarter of 2007, the Company will be completing the NEB oral hearing for the Canadian portion of the pipeline project. In the United States, the various federal and state regulatory processes and related hearings are continuing. In concert with the Southern Access project, construction activities are underway on the 321 mile section from Superior to Delavan, Wisconsin with over 85% of welding completed. Assuming required approvals are received, the diluent line is expected to be in service in 2010.

Based on construction costs experienced on the initial phase of the project, the expected capital cost has been updated to an estimated US$2.2 billion. Based on this level of costs, the project will earn a minimum return on equity of 10% plus a premium return which depends on the extent to which throughput on the line exceeds 90% of capacity.

Terminalling and Tankage Infrastructure

The Company is increasing its investment in contract terminals through the construction of upstream terminals at Hardisty and Stonefell, Alberta, as well as downstream terminals in the Midwest and U.S. Gulf Coast.

Stonefell Terminal

Enbridge has agreed to provide pipeline and terminalling services through construction of the Stonefell Terminal to BA Energy Inc.’s new bitumen upgrader near Fort Saskatchewan, Alberta. Detailed engineering and the majority of the civil construction was completed in early August. Construction is underway on the six tanks and ancillary facilities.

Hardisty Terminal

Enbridge is building a $0.4 billion crude oil terminal at Hardisty, Alberta with a storage capacity of 7.5 million barrels. Regulatory delays affected the estimated in-service date and it is now expected that the

-6-

terminal will be completed in phases from late 2008 through mid-2009. Civil construction of the 19 tank pads was completed at the end of September and tankage construction is underway.

Alberta Royalty Review

On October 25, 2007, the Alberta government issued “The New Royalty Framework” report summarizing upcoming changes to the Alberta Royalty Program. The new Framework is effective January 2009 and involves increasing royalty rates and rate caps for conventional oil, natural gas and oil sands to adjust to fluctuating oil prices. This Framework could create economic hurdles for future oil sands development, which may affect the pace of future growth in volumes expected to flow through Enbridge’s Liquids Pipeline Systems. As outlined in Enbridge’s submission to the Royalty Review Panel, Enbridge shares its customers’ need to ensure that Alberta remains a competitive business environment with a stable, positive and predictable investment climate. Enbridge is reviewing the government’s proposed changes to the royalty regime and will be working closely with customers to better understand the implications of those changes over the coming weeks.

Gas Pipelines

The Company is growing the Gas Pipelines segment by expanding its reach in the Gulf of Mexico through connecting new oil and gas fields in the Gulf coast to its existing Gulf of Mexico infrastructure and by expanding the capacity of the Vector Pipeline. Progress made on these projects in 2007 to date is as follows:

Vector Pipeline

Vector Pipeline continues to progress with a US$0.1 billion expansion from 1.0 billion cubic feet/day (bcf/d) to 1.2 bcf/d. Vector has obtained FERC approval for the expansion and secured 10-year firm transportation contracts for the new capacity. Construction continued during the quarter and the expansion is expected to be in service in the fourth quarter of 2007.

Neptune Pipeline

Construction of the US$0.1 billion 26-mile (42-kilometre), 20-inch diameter oil pipeline with capacity of 60,000 bpd and 26-mile, 12-inch diameter gas pipeline, with capacity of 0.2 bcf/d, will be completed in the fourth quarter of 2007. The Company will start collecting standby fees in fourth quarter 2007.

Shenzi Pipeline

Construction of the US$45 million 11-mile, 12-inch diameter gas pipeline, with capacity of 0.1 bcf/d, is scheduled for the first quarter of 2008. In-service continues to be scheduled for mid 2009.

Atlantis and Thunder Horse Production Projects

Both of these significant third party-owned projects, which will deliver natural gas into Enbridge Offshore gathering systems, have experienced continuing startup delays due to the severe 2005 hurricanes. The operator of these projects now expects Atlantis to be in service in the fourth quarter of 2007 and Thunder Horse to be in service in the fourth quarter of 2008.

Sponsored Investments

Enbridge’s affiliate, EEP, is expanding and extending its East Texas System in response to increased demand for EEP’s treating and processing services. As well, increased demand for crude oil transportation has resulted in the expansion of EEP’s North Dakota System. Progress made on these projects in 2007 to date is as follows:

East Texas System Expansion and Extension (Project Clarity)
Project Clarity includes the construction of a 36-inch diameter pipeline to interstate and intrastate markets. This project is adding 0.7 bcf/d capacity to the current East Texas infrastructure. All phases of the project are complete with the exception of the Kountze, Texas to Orange, Texas stage which is expected to be completed in the first quarter of 2008.

-7-

North Dakota System Expansion

On June 18, 2007, EEP commenced a binding Open Season for the proposed US$0.2 billion Phase 6 expansion of the Enbridge North Dakota Pipeline System. The Phase 6 expansion, if fully subscribed, would increase system capacity from 110,000 bpd to 161,000 bpd by the end of 2009. The commercial structure for this expansion has been modified to a cost-of-service based surcharge that will be added to the existing tariff rates.

Gas Distribution and Services

Developments within Gas Distribution and Services relate primarily to Enbridge Gas Distribution and include: the finalization of the annual rate application with the Ontario Energy Board (OEB); the application for a new rate setting methodology, namely Incentive Regulation (IR), for 2008; the development of natural gas storage services in Southwestern Ontario; as well as the finalization of customer care service contracts and the development of a new Customer Information System (CIS). The Company also continues to develop and grow its wind power and LNG platforms through the Ontario Wind Project and Rabaska LNG facility, respectively. In addition, during the third quarter, the Company sold an option for the purchase of its ownership interest in Netthruput (NTP). Details on these developments and progress made on these projects in 2007 to date is as follows:

2007 Rate Application — EGD

EGD filed its 2007 rate application with the OEB in August 2006 which consisted of a traditional cost of service methodology application. During the first quarter, the OEB approved settlements reached with stakeholders related to capital, operating and maintenance expenditure budgets, permitting EGD to implement a partial rate increase effective April 1, 2007. EGD has implemented an additional rate increase on October 1, 2007, which will enable EGD to recover the approved amounts retroactively to January 1, 2007. The key elements of the decision are summarized below:


Approved for the regulatory year ending December 31,	2007			2006

Rate base (millions)	$	3,745.7		$	3,633.6
Deemed common equity for regulatory purposes		36	%		35	%
Rate of return on common equity		8.39	%		8.74	%

EGD was granted a 1% increase in the equity component of its deemed capital structure to 36% from 35% reflecting changes in EGD’s business risk environment and financial risk position. In addition, a new 20 year trend method to calculate normal weather for EGD’s main franchise area, the Greater Toronto Area, was approved. Finally, EGD was directed to cease its risk management program, which utilized price swaps, calls and collars to manage the volatility in the price of natural gas. Consistent with prior years, changes in the price of natural gas flow through to the customer.

Rate Regulation — Incentive Regulation

During 2006, EGD commenced consultation with the OEB with respect to shifting to an IR methodology for rate setting purposes. EGD expects that IR will start in 2008, with 2007 as the base year for a potential five year plan. During the second quarter, the OEB directed EGD to file an application for rates commencing in 2008 based on an IR methodology, which EGD filed in the third quarter of 2007. The Company has requested a revenue cap incentive rate mechanism calculated on a revenue per customer basis for the 2008 to 2012 period. The regulatory hearing process on the IR model is expected to occur during the remainder of 2007, with a final decision expected in the second quarter of 2008.

Storage Project

In April 2007, EGD signed storage contracts to provide daily services totaling 2.8 million gigajoules (GJ), or approximately 2.6 bcf, of storage capacity, including 10 or 20-day storage service with firm year-round withdrawal and injection levels. On July 30, 2007, the OEB released a final decision

-8-

upholding an earlier decision to cease regulating prices for any new storage services offered by EGD. As a result, EGD will proceed with development of the project.

Customer Care and Customer Information System Agreements

Effective April 1, 2007, EGD entered into five-year customer care services contracts with third party service providers for meter reading, billing, billing administration, call handling and collections. The total cost of the contracts is approximately $274 million over the five year term. EGD is planning to have a new CIS system in service by July 2009 to meet regulatory requirements and to meet the need for a more robust and technologically up-to-date system. The OEB has approved a six-year rate recovery arrangement for the customer care services and a ten-year recovery of the $119 million in capital to be invested in the new CIS.

Ontario Wind Project

On July 20, 2007, the Ontario Municipal Board and the Ontario Ministry of the Environment ruled in favour of the construction of Enbridge’s Ontario Wind Project in the municipality of Kincardine. This was the final approval required and subsequently construction has commenced with access roads, turbine foundations, electrical sub-station and utility transmission lines. The $0.5 billion project is expected to produce 182 megawatts of electricity and, on completion, will be one of the largest wind power projects in Canada. The project is expected to begin producing electricity during the latter half of 2008.

Rabaska LNG Facility

Enbridge, Gaz Metro and Gaz de France are continuing development of the $0.8 billion Rabaska LNG terminal to be located on the St. Lawrence River in Levis, Quebec. Marine and environmental applications have been approved by government agencies. Federal and Provincial government approvals were received in October 2007.

Netthruput

During the third quarter, the Company and its partner in NTP entered into an agreement with the TSX Group granting the TSX Group the option to purchase NTP, an internet-based crude oil trading and clearing platform. The option may be exercised at a time after March 15, 2009 for a price between $40 million and $95 million depending on NTP’s 2008 net earnings. The agreement also provides the Company and its partner in NTP an option to sell NTP under the same terms to the TSX Group. The Company has a 52% ownership interest in NTP.

Bloor Street Incident

The Company had been charged under both the Ontario Technical Standards and Safety Act (the TSSA) and the Ontario Occupational Health and Safety Act (the OHSA) in connection with an explosion that occurred on Bloor Street West in Toronto on April 24, 2003. On October 25, 2007, all of the TSSA and OHSA charges laid against the Company were dismissed by the Ontario Court of Justice. The decision may be appealed by the Crown to the Ontario Superior Court of Justice within 30 days after October 25, 2007 and the Company is not aware at the present time whether the Crown plans to appeal. The maximum possible fine upon conviction on all charges would have been approximately $5.0 million in the aggregate.

The Company has also been named as a defendant in a number of civil actions related to the explosion. A Coroner’s Inquest in connection with the explosion is also possible. The majority of the civil actions have been settled and the Company does not expect the civil actions to result in any material financial impact.

-9-

FINANCIAL RESULTS

Liquids Pipelines
Earnings

Three months ended

Nine months ended

September 30,

(millions of Canadian dollars)

2007

2006

2007

2006

Enbridge System

46.4

49.0

140.6

149.9

Athabasca System

10.8

14.0

37.4

40.1

Olympic Pipeline

2.5

2.2

7.7

4.8

Spearhead Pipeline

1.6

0.4

6.0

3.1

Feeder Pipelines and Other

1.1

2.5

5.4

5.1

62.4

68.1

197.1

203.0

Earnings from Liquids Pipelines for the nine months ended September 30, 2007 were lower than the prior year by $5.9 million, primarily due to declines in Enbridge and Athabasca Systems earnings which were largely a result of increased costs. This decrease was partially offset by stronger performance by Olympic and Spearhead pipelines.

Enbridge System earnings decreased from the prior year due to higher compensation expense driven by a strong labour market, higher pipeline integrity costs and increased taxes in the Terrace component, partially offset by lower oil loss costs.

Athabasca System earnings decreased from the prior year due to higher property taxes and the costs of minor leak remediation in 2007.

Olympic Pipeline was acquired on February 1, 2006. Earnings for 2007 reflected a full nine months of operations as well as higher tolls in 2007 to compensate for under shipments in 2006. Olympic’s cost of service tolling methodology requires annual toll adjustments for over or under collections in prior years.

Spearhead Pipeline commenced operations in early March 2006. Earnings for 2007 reflected a full nine months of operations as well as increased throughput. The third quarter of 2006 reflected higher operating costs due to timing.

Earnings for the three months ended September 30, 2007 were $62.4 million compared with $68.1 million for the three months ended September 30, 2006. The decrease was primarily due to a reduction in Enbridge and Athabasca Systems earnings for the same reasons as noted for the nine month results. In addition, Feeder Pipelines and Other earnings were reduced by increased business development costs on projects in the early development stage.

Gas Pipelines
Earnings

Three months ended

Nine months ended

September 30,

(millions of Canadian dollars)

2007

2006

2007

2006

Alliance Pipeline US

6.6

7.8

21.4

22.3

Vector Pipeline

3.8

2.5

10.7

9.3

Enbridge Offshore Pipelines

1.5

4.8

18.9

15.4

11.9

15.1

51.0

47.0

-10-

Earnings from Gas Pipelines were $51.0 million for the nine months ended September 30, 2007, an increase of $4.0 million from the same period in the prior year due primarily to insurance proceeds at Offshore.

Enbridge Offshore Pipelines earnings for the nine month period included $11.3 million of insurance proceeds for both property insurance recoveries and business interruption resulting from the 2005 hurricanes. The final insurance claim settlement is expected in late 2007 or early 2008. Offshore earnings also reflected the impact of a weaker U.S. dollar, continuing repair and inspection costs and continuing expected natural production declines on deliveries to the pipelines in 2007. Start up issues experienced by producers on key production platforms, resulting from the effects of the extreme 2005 hurricane season, continue to delay new sources of volumes.

For the three months ended September 30, 2007, Gas Pipelines earned $11.9 million compared with $15.1 million for the three months ended September 30, 2006. The decrease reflected a reduction in Offshore’s third quarter earnings due to impacts of natural production declines on deliveries to the pipelines. In addition, Gas Pipelines earnings were reduced by the weakening of the U.S. dollar. However, Vector’s earnings remained stronger in the quarter due to lower scheduled integrity costs in 2007.

Sponsored Investments
Earnings



	Three months ended				Nine months ended
	September 30,				September 30,
(millions of Canadian dollars)	2007		2006		2007			2006


Enbridge Energy Partners		12.2		12.1		32.6			31.5
Enbridge Income Fund (EIF)		9.2		9.8		28.5			27.8
Dilution gain in EEP		—		—		11.8			—
Revalue future income taxes due to tax changes in EIF		—		—		(0.3	)		6.0

		21.4		21.9		72.6			65.3

Earnings for the nine months ended September 30, 2007 were $72.6 million compared with $65.3 million in the same period of 2006. The increase was due to dilution gains in EEP partially offset by a more significant impact of tax changes on future income tax balances in 2006.

EEP’s nine month 2007 earnings, after adjusting for unrealized derivative fair value gains and losses, increased reflecting the increase in Enbridge’s ownership interest from 10.9% to 16.6% during the third quarter of 2006. EEP’s earnings increased from the prior year as increased throughput on principal natural gas and liquids systems was partially offset by higher operating expenses. Nine month results were also negatively impacted by higher natural gas measurement losses and a processing plant temporary shutdown for maintenance during the second quarter of 2007, as well as the impact of a weaker U.S. dollar.

EEP issued partnership units in the second quarter of 2007, reducing Enbridge’s ownership interest from 16.6% to 15.0%. Enbridge did not fully participate in the issue resulting in a dilution gain.

In 2007, EIF recognized future taxes within entities that will become taxable in 2011 as a result of the enactment of Bill C-52 “The Tax Fairness Plan”. This future tax increase was partially offset by the revaluation of future income tax obligations previously recorded as a result of tax rate reductions. Under Bill C-52, EIF will be taxable starting in 2011. EIF is carefully assessing the impact of the legislation on its business and financial outlook as well as the broader effect on the income trust sector as a whole, all with a view to adopting a strategy that will maximize value to unitholders going forward. The prior year included the impact of larger tax rate reductions.

-11-

Earnings for the three months ended September 30, 2007 were comparable with the prior year. Increased earnings in EEP due to a higher ownership interest were offset by the impact of a weaker U.S. dollar.

Gas Distribution and Services

Earnings



	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


Enbridge Gas Distribution		(29.5	)		(27.8	)		74.3			25.4
Noverco		(5.8	)		(3.9	)		10.2			11.2
CustomerWorks/ECS		1.0			5.7			6.5			16.0
Enbridge Gas New Brunswick		3.1			2.8			9.0			7.1
Other Gas Distribution		(0.9	)		(1.2	)		5.2			4.1
Energy Services		3.8			(0.6	)		4.3			3.1
Aux Sable		4.7			14.9			(3.5	)		16.1
Other		(1.1	)		(1.3	)		(1.4	)		(3.3	)
Revalue future income taxes due to tax rate changes		—			—			3.8			28.9

		(24.7	)		(11.4	)		108.4			108.6

Earnings were $108.4 million for the nine months ended September 30, 2007, compared with $108.6 million for the nine months ended September 30, 2006. Earnings decreased primarily due to the impact of tax rate reductions on future income tax balances in 2006, as well as decreases in Aux Sable and CustomerWorks earnings, but were offset by higher earnings from EGD.

EGD’s earnings improved from the prior year primarily due to the impact of colder weather. During 2006, weather was significantly warmer than normal, resulting in lower earnings, whereas in 2007 weather has been colder than normal. Earnings also increased because of customer growth and higher operating margins. The third quarter is seasonally warm and therefore fixed costs are typically not covered during this quarter resulting in losses.

CustomerWorks/ECS earnings decreased because, pursuant to an OEB recommendation, CustomerWorks transitioned customer care services related to EGD to a third party service provider.

Energy Services earnings, after adjusting for unrealized fair value gains and losses on derivative instruments, were stronger in 2007 due to increased optimization of Enbridge assets, improved market fundamentals for crude oil and increased transportation and storage volumes, all at Tidal Energy. Energy Services includes Gas Services and Tidal Energy. Tidal Energy was included in Other in prior years.

Segment losses for the three months ended September 30, 2007 were $24.7 million, compared with $11.4 million for the same period in the prior year. The increased loss is primarily due to derivative hedge losses at Aux Sable.

-12-

International
Earnings



	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


CLH		15.3			14.5			46.5			42.5
OCENSA/CITCol		8.1			8.4			24.5			24.7
Other		(0.8	)		(1.8	)		(2.4	)		(3.0	)

		22.6			21.1			68.6			64.2

Earnings for the nine months ended September 30, 2007 were $68.6 million, compared with $64.2 million for the same period in 2006. CLH earnings increased due to higher transportation tariffs, higher volumes and the impact of a stronger Euro. Other includes lower business development costs in 2007 due to a de-emphasizing of business development activities within the International segment.

Earnings for the three months ended September 30, 2007 reflect similar factors as those for the nine-month results.

Corporate
Costs



	Three months ended						Nine months ended
	September 30,						September 30,
(millions of Canadian dollars)	2007			2006			2007			2006


Corporate		(15.5	)		(19.3	)		(46.1	)		(57.8	)
Revalue future income taxes due to tax rate changes		—			—			—			14.0

		(15.5	)		(19.3	)		(46.1	)		(43.8	)

Corporate costs totaled $46.1 million for the nine months ended September 30, 2007, compared with $43.8 million for the nine months ended September 30, 2006. The increase in Corporate costs was primarily due to tax rate changes which benefited the second quarter of 2006. However, the increase was partially offset by decreased interest expense resulting from lower levels of Corporate debt during the first half of 2007 which was repaid from the net proceeds of the $566.4 million issuance of equity on February 2, 2007. Interest expense in Corporate was also lower in the second and third quarters of 2007 because of higher interest capitalization related to projects under construction.

LIQUIDITY AND CAPITAL RESOURCES

The Company expects to generate sufficient cash from operations and debt issuances to fund liabilities as they become due, finance budgeted investing activity and pay common share dividends throughout 2007. Additional liquidity, if necessary, is available under committed credit facilities or through access to the capital markets. At September 30, 2007, the Company had $3.2 billion available under unused credit facilities, of which $0.9 billion was used to backstop commercial paper.

Operating Activities
Cash from operations was $1,101.8 million for the nine months ended September 30, 2007, a decrease of $64.6 million from the comparable prior year period. The decrease was due to non-cash changes in operating assets and liabilities, mainly driven by a larger replenishment of gas inventory in 2007 as a result of a relatively colder winter. Partially offsetting this was the receipt of insurance proceeds at EOP.

Cash used in operating activities for the three month period ended September 30, 2007 was $45.9 million higher than the comparative period. This was primarily due to realized hedge losses in Aux

-13-

Sable, lower earnings from the Enbridge and Athabasca Systems as a result of higher operating costs, and the effect of the weakening U.S. dollar.

Investing Activities

Cash used for investing activities was $1,533.0 million (2006 — $1,110.2 million) for the nine months ended September 30, 2007. The increase reflected higher expenditures on property, plant and equipment due to construction activities on various projects. In addition, higher ongoing capital improvements and core maintenance expenditures were incurred primarily at EGD and Enbridge System. There were no acquisitions in the current year, whereas the prior year included $101.4 million for the 65% joint venture interest in Olympic Pipeline.

Cash used in investing activities during the quarter increased by $52.9 million from the prior year reflecting increased capital expenditures, primarily due to growth projects such as Southern Lights U.S. and the Waupisoo Pipeline. Offsetting this increase in capital expenditures was prior year spending in the third quarter to increase the Company’s investment in EEP.

Financing Activities

The Company’s debt to capitalization ratio was 61.9% at September 30, 2007 compared with 64.4% at September 30, 2006 primarily as a result of issuing common shares for $566.4 million during the first quarter. The proceeds were used to pay down corporate debt including the redemption of $200.0 million of preferred securities.

Cash provided by financing activities during the nine months ended September 30, 2007 was $462.4 million compared with a use of cash of $12.1 million for the nine months ended September 30, 2006. Financing activities in the period included the issuance of common shares as mentioned above as well as the issuance of US$400.0 million of long-term debt in the first quarter and US$650.0 million in the second quarter. These financing activities were used to repay short-term debt and finance new growth projects at attractive long-term interest rates. Short term borrowings decreased in the first half of 2007 commensurate with a similar reduction in EGD’s gas inventory. However, short-term borrowings and short-term debt increased in the third quarter of 2007 by $355.0 million compared to the same period in the prior year. This incremental increase in short-term borrowings in the quarter was used to fund growth projects as well as to repay $100 million of debt in July 2007. Dividend distributions increased from the prior year as more shares were outstanding and a higher dividend rate is being paid in the current year.

On August 31, 2007, a new credit facility was arranged to fund project costs directly related to the Southern Lights Project. This US$500 million facility has a 364 day term.

Debt Covenants

EGD has met the long-term debt issuance covenant contained in its trust indenture and is again able to issue new long-term debt as earnings for interest coverage improved as a result of the 2007 winter months being colder than the prior year as well as customer additions and positive operating margins. To issue new long-term debt, EGD is required to have a long-term debt interest coverage ratio of 2.0 times for 12 consecutive months in the previous 23 months.

Construction Commitments

The Company has signed contracts totaling $779 million for the purchase of pipe and other materials, to be used in the construction of several liquids pipelines projects including the Southern Lights project, the Alberta Clipper project, the Southern Access Expansion and Extension projects as well as the Line 4 Extension project. The Company expects to take delivery of the pipe concurrent with the project schedules. Commitments associated with these contracts are supported by industry as necessary to expedite the project in-service dates.

-14-

Oil Loss Claim

Operating conditions in 2005 were identified on connected third-party systems that were contributing to higher levels of physical losses on Enbridge System. The Company has addressed the operating conditions causing these higher levels of physical losses, which have subsequently reduced the physical losses experienced on Enbridge System. The Company has begun proceedings to recover damages for the losses sustained from the owner of these third-party systems, but no assurances can be given as to the time to completion or the results of the recovery process. In addition, any recovery would be, under the incentive tolling settlement, shared with shippers in respect of the Canadian portion of the claim.

CHANGES IN ACCOUNTING POLICIES

Financial Instruments, Comprehensive Income and Hedging Relationships

Effective January 1, 2007, the Company adopted new accounting standards for Financial Instruments - Recognition and Measurement, Financial Instruments — Disclosure and Presentation, Comprehensive Income and Hedges. These policies were adopted prospectively and, accordingly, the prior periods were not restated. However, unrealized gains and losses related to the Company’s foreign currency translation adjustments and net investment hedges are now included in Accumulated Other Comprehensive Income or Loss (AOCI) and unamortized deferred financing fees of $52.7 million were reclassified from deferred amounts and other assets to long-term debt.

The new standards require that the Company now recognize financial instruments, including cash flow and fair value hedges, on the balance sheet at fair value. The standards also require the classification of financial assets and liabilities according to expected use. Loans and receivables and instruments held to maturity remain recorded at amortized cost. With the exception of recognizing derivative instruments, including hedge instruments, at fair value, the Company has not changed the valuation of other financial instruments.

The adoption of the new standards did not impact the Company’s earnings or cash flows; however, the Company recognized assets of $3.4 million, liabilities of $2.2 million, AOCI of $48.2 million and a decrease to retained earnings of $47.0 million as at January 1, 2007.

To the extent cash flow hedges are effective, the unrealized changes in fair value are recognized as assets or liabilities with the offset recorded in Accumulated Other Comprehensive Income, a component of equity, until the gains or losses are realized and recognized in earnings. Any hedge ineffectiveness is charged to current earnings. Unrealized changes in fair value hedges are recorded in earnings consistent with changes in the fair value of the underlying asset or liability. For the Company’s regulated operations, certain derivatives are recognized at fair value on the balance sheet with an offsetting regulatory asset or liability.

The Company does not use derivatives for speculative purposes, although certain economic hedges may fail to qualify for hedge accounting. For derivatives that do not qualify for hedge accounting, the unrealized changes in fair value are charged to current earnings. The Company also utilizes fixed price forward physical commodity contracts to manage exposure to changes in commodity prices. Certain of the Company’s fixed price contracts are deemed derivatives; therefore, are recognized at fair value. Unrealized gains and losses are reflected in earnings.

Capital Disclosures and Financial Instruments — Disclosure and Presentation

-15-

compliance requirements, as well as enhanced disclosure of risks associated with financial instruments and how those risks are managed.

SELECTED QUARTERLY FINANCIAL INFORMATION¹


(millions of Canadian dollars, except per share amounts)	2007						2006								2005
	Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4

Revenues		2,634.0		2,728.7		3,358.2		2,785.7		2,184.9		2,327.2		3,346.7		2,712.8
Earnings applicable to common shareholders		78.1		146.5		227.0		171.1		95.5		157.9		190.9		174.0
Earnings per common share		0.22		0.41		0.65		0.50		0.28		0.47		0.56		0.52
Diluted earnings per common share		0.22		0.41		0.64		0.49		0.28		0.46		0.56		0.51
Dividends per common share		0.3075		0.3075		0.3075		0.2875		0.2875		0.2875		0.2875		0.2875


¹		Quarterly Financial Information has been extracted from financial statements prepared in accordance with Canadian GAAP.

Revenue includes amounts billed to customers of EGD for natural gas, which varies with fluctuations in the commodity price. Higher natural gas commodity prices increase revenues, but would not similarly impact earnings, given that the cost of natural gas flows through to customers. Fluctuations in commodity prices also impact revenues from Energy Services businesses.

In addition, revenue fluctuates due to the seasonality of EGD. Typically, revenue peaks in the winter months during the first quarter and, to a lesser extent, in the fourth quarter of the year when higher gas volumes are sold. Finally, EGD’s revenue and earnings are affected by variations in the weather, especially in the winter, when warmer or colder than normal temperatures can result in lower or higher distribution volumes, respectively.

Significant items that impacted the quarterly earnings and revenue, in addition to the seasonal fluctuations described above, were as follows:

	•		Third quarter 2007 included lower earnings from Aux Sable due to hedge losses.

	•		Second quarter 2007 included higher earnings from EGD due to colder than normal weather and a dilution gain of $11.8 million in EEP.

	•		First quarter 2007 included higher earnings from EGD due to colder weather than the prior year period and the receipt of 2005 hurricane insurance proceeds.

	•		Fourth quarter earnings in 2006 reflected higher earnings from the Enbridge System and Aux Sable, offset by lower earnings from EGD due primarily to warmer than normal weather and higher costs.

	•		Third quarter earnings in 2006 reflected higher earnings from Enbridge System, increased earnings from the Company’s investment in EEP and the initial recognition of upside sharing in Aux Sable.

	•		Second quarter earnings in 2006 included the impact of tax rate reductions, which increased consolidated earnings by $48.9 million.

	•		First quarter earnings in 2006 reflected increased earnings in Enbridge System more than offset by lower results from EGD, due primarily to warmer than normal weather. Revenues in the first quarter of 2006 were higher due to higher commodity prices and were offset by higher commodity costs.

	•		Fourth quarter earnings in 2005 included a gain of $7.6 million on the sale of land in CLH and a dilution gain of $4.3 million in EEP.

-16-

OUTSTANDING SHARE DATA


	Number of Shares


Common Shares — issued and outstanding (voting equity shares)		368,284,639
Preference Shares, Series A (non-voting equity shares)		5,000,000
Total issued and outstanding stock options (7,224,860 vested)		12,954,209

Outstanding share data information is provided as at October 30, 2007.

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.

-17-

ENBRIDGE INC.
HIGHLIGHTS



	Three months ended						Nine months ended
(unaudited; millions of Canadian dollars, except per share amounts)	September 30,						September 30,
	2007			2006			2007			2006

Earnings Applicable to Common Shareholders
Liquids Pipelines		62.4			68.1			197.1			203.0
Gas Pipelines		11.9			15.1			51.0			47.0
Sponsored Investments		21.4			21.9			72.6			65.3
Gas Distribution and Services		(24.7	)		(11.4	)		108.4			108.6
International		22.6			21.1			68.6			64.2
Corporate		(15.5	)		(19.3	)		(46.1	)		(43.8	)

		78.1			95.5			451.6			444.3

Cash Flow Data
Cash provided by operating activities before changes in operating assets and liabilities		212.9			230.8			935.3			816.4
Cash provided by/(used in) operating activities		(79.4	)		(33.4	)		1,101.8			1,166.4
Additions to property, plant and equipment		672.6			275.8			1,574.2			676.5
Acquisitions and long-term investments		4.3			291.9			19.7			448.2
Common share dividends		113.1			100.6			338.9			302.0

Per Share Information
Earnings per Common Share		0.22			0.28			1.27			1.31
Diluted Earnings per Common Share		0.22			0.28			1.26			1.30
Dividends per Common Share		0.3075			0.2875			0.9225			0.8625

Shares Outstanding (millions)
Weighted Average Common Shares Outstanding		356.2			340.4			354.7			339.6
Diluted Weighted Average Common Shares Outstanding		359.5			344.5			357.7			342.9

Operating
Liquids Pipelines — Deliveries (thousands of barrels per day)
Enbridge System¹		1,977			2,007			2,001			1,972
Athabasca System²		175			187			165			192
Spearhead Pipeline		91			67			97			70
Olympic Pipeline		285			292			287			294
Gas Pipelines — Average Daily Throughput Volume (millions of cubic feet per day)
Alliance Pipeline US		1,535			1,513			1,606			1,595
Vector Pipeline		974			879			984			1,014
Enbridge Offshore Pipelines		2,201			2,265			2,118			2,190
Gas Distribution and Services³
Volumes (billion cubic feet)		48			45			316			285
Number of active customers (thousands)		1,880			1,829			1,880			1,829
Degree day deficiency⁴
Actual⁵		45			85			2,439			2,190
Forecast based on normal weather		92			58			2,380			2,498


^1.		Enbridge System includes Canadian mainline deliveries in Western Canada and to the Lakehead System at the U.S. border, as well as Line 8 and Line 9 in Eastern Canada.

^2.		Volumes are for the Athabasca mainline only and do not include laterals on the Athabasca System.

^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 which is indicative of volumetric requirements of natural gas utilized for heating purposes. 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 Greater Toronto Area.

^5.		Given that degree days are largely ineffective during the non-heating season, there was no measurable impact on earnings in the third quarter. Degree days are fully effective, typically in the peak winter months, when their occurrence directly impacts the consumption pattern by a similar magnitude.

-18-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS



	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars, except per share amounts)	2007			2006			2007			2006


Revenues
Commodity sales		2,124.8			1,645.0			6,972.4			6,141.5
Transportation		456.4			453.5			1,541.4			1,515.7
Energy services		52.8			86.4			207.1			201.6

		2,634.0			2,184.9			8,720.9			7,858.8

Expenses
Commodity costs		2,004.6			1,562.4			6,583.4			5,850.0
Operating and administrative		290.0			256.6			844.9			759.9
Depreciation and amortization		151.0			145.4			450.0			437.6

		2,445.6			1,964.4			7,878.3			7,047.5

		188.4			220.5			842.6			811.3
Income from Equity Investments		31.4			35.9			111.8			134.0
Other Investment Income		24.9			33.2			133.5			83.4
Interest Expense		(135.6	)		(142.2	)		(409.4	)		(417.3	)

		109.1			147.4			678.5			611.4
Non-Controlling Interests		(9.7	)		(13.4	)		(34.7	)		(46.6	)

		99.4			134.0			643.8			564.8
Income Taxes		(19.6	)		(36.8	)		(187.1	)		(115.4	)

Earnings		79.8			97.2			456.7			449.4
Preferred Share Dividends		(1.7	)		(1.7	)		(5.1	)		(5.1	)

Earnings Applicable to Common Shareholders		78.1			95.5			451.6			444.3


Earnings Per Common Share		0.22			0.28			1.27			1.31


Diluted Earnings Per Common Share		0.22			0.28			1.26			1.30

See accompanying notes to the unaudited consolidated financial statements.

-1-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three months ended						Nine months ended
	September 30,						September 30,
(unaudited; millions of Canadian dollars)	2007			2006			2007			2006

Earnings		79.8			97.2			456.7			449.4
Other Comprehensive Income/(Loss)
Change in unrealized gains on cash flow hedges, net of tax		17.6			—			59.1			—
Reclassification to earnings of realized cash flow hedges, net of tax		(8.1	)		—			8.8			—
Other comprehensive gain/(loss) from equity investees		0.5			—			(4.5	)		—
Non-Controlling interest in other comprehensive income		(1.8	)		—			1.2			—
Change in foreign currency translation adjustment		(164.8	)		(5.4	)		(443.5	)		(89.3	)
Change in unrealized gains on net investment hedges, net of tax		66.7			13.1			166.8			43.6

Comprehensive Income		(10.1	)		104.9			244.6			403.7

See accompanying notes to the unaudited consolidated financial statements.

-2-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY



	Nine months ended
	September 30,

(unaudited; millions of Canadian dollars)	2007			2006


Preferred Shares		125.0			125.0


Common Shares
Balance at beginning of period		2,416.1			2,343.8
Common shares issued		566.4			—
Dividend reinvestment and share purchase plan		13.9			14.0
Shares issued on exercise of stock options		21.4			41.9

Balance at End of Period		3,017.8			2,399.7


Contributed Surplus
Balance at beginning of period		18.3			10.0
Stock-based compensation		8.1			5.8
Option exercises		(1.2	)		(1.8	)

Balance at End of Period		25.2			14.0


Retained Earnings
Balance at beginning of period		2,322.7			2,098.2
Earnings applicable to common shareholders		451.6			444.3
Cumulative impact of change in accounting policy (Note 1)		(47.0	)		—
Common share dividends		(338.9	)		(302.0	)
Dividends paid to reciprocal shareholder		10.3			9.1

Balance at End of Period		2,398.7			2,249.6


Accumulated Other Comprehensive Loss
Balance at beginning of period		(135.8	)		(171.8	)
Cumulative impact of change in accounting policy (Note 1)		48.2			—
Other comprehensive loss (Note 1)		(212.1	)		(45.7	)

Balance at End of Period		(299.7	)		(217.5	)


Reciprocal Shareholding
Balance at beginning of period		(135.7	)		(135.7	)
Participation in common shares issued		(18.6	)		—

Balance at End of Period		(154.3	)		(135.7	)

Total Shareholders’ Equity		5,112.7			4,435.1

See accompanying notes to the unaudited consolidated financial statements.

-3-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three months ended						Nine months ended
	September 30,						September 30,

(unaudited; millions of Canadian dollars)	2007			2006			2007			2006


Cash Provided By Operating Activities
Earnings		79.8			97.2			456.7			449.4
Depreciation and amortization		151.0			145.4			450.0			437.6
Unrealized losses on derivative instruments		10.5			—			24.0			—
Equity earnings in excess of cash distributions		(14.2	)		(20.2	)		(42.1	)		(63.0	)
Gain on reduction of ownership interest		—			—			(33.9	)		—
Future income taxes		(36.8	)		(4.6	)		34.5			(52.7	)
Other		22.6			13.0			46.1			45.1
Changes in operating assets and liabilities		(292.3	)		(264.2	)		166.5			350.0

		(79.4	)		(33.4	)		1,101.8			1,166.4

Investing Activities
Acquisitions		—			—			—			(101.4	)
Long-term investments		(4.3	)		(291.9	)		(19.7	)		(346.8	)
Additions to property, plant and equipment		(672.6	)		(275.8	)		(1,574.2	)		(676.5	)
Affiliate loans		—			—			—			28.0
Change in construction payable		57.2			0.8			60.9			(13.5	)

		(619.7	)		(566.9	)		(1,533.0	)		(1,110.2	)

Financing Activities
Net change in short-term borrowings and short-term debt		811.7			456.7			(298.7	)		(96.5	)
Net change in non-recourse short-term debt		11.7			(9.7	)		18.9			(5.2	)
Long-term debt issues		—			300.0			1,156.6			800.0
Long-term debt repayments		(100.0	)		—			(634.5	)		(400.0	)
Non-recourse long-term debt issues		—			—			14.4			2.8
Non-recourse long-term debt repayments		(2.9	)		—			(31.6	)		(29.7	)
Contributions from/(distributions to) non-controlling interests		0.8			(5.5	)		(11.9	)		(25.4	)
Common shares issued		7.0			10.5			593.2			49.0
Preferred share dividends		(1.7	)		(1.7	)		(5.1	)		(5.1	)
Common share dividends		(113.1	)		(100.6	)		(338.9	)		(302.0	)

		613.5			649.7			462.4			(12.1	)

Increase/(Decrease) in Cash and Cash Equivalents		(85.6	)		49.4			31.2			44.1
Cash and Cash Equivalents at Beginning of Period		256.5			148.6			139.7			153.9

Cash and Cash Equivalents at End of Period		170.9			198.0			170.9			198.0

See accompanying notes to the unaudited consolidated financial statements.

-4-

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION



	September 30,			December 31,
(unaudited; millions of Canadian dollars)	2007			2006


Assets
Current Assets
Cash and cash equivalents		170.9			139.7
Accounts receivable and other		2,046.7			2,045.6
Inventory		867.0			868.9

		3,084.6			3,054.2
Property, Plant and Equipment, net		12,037.0			11,264.7
Long-Term Investments		2,098.2			2,299.4
Deferred Amounts and Other Assets		1,063.7			924.5
Intangible Assets		215.4			241.5
Goodwill		381.7			394.9
Future Income Taxes		210.2			200.1

		19,090.8			18,379.3


Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings		570.8			807.9
Accounts payable and other		2,022.0			1,723.8
Interest payable		98.8			95.1
Current maturities and short-term debt		452.7			537.0
Current portion of non-recourse debt		56.8			60.1

		3,201.1			3,223.9
Long-Term Debt		7,295.7			7,054.0
Non-Recourse Long-Term Debt		1,520.9			1,622.0
Other Long-Term Liabilities		278.3			91.1
Future Income Taxes		1,030.0			1,062.5
Non-Controlling Interests		652.1			715.2

		13,978.1			13,768.7

Shareholders’ Equity
Share capital
Preferred shares		125.0			125.0
Common shares		3,017.8			2,416.1
Contributed surplus		25.2			18.3
Retained earnings		2,398.7			2,322.7
Accumulated other comprehensive loss		(299.7	)		(135.8	)
Reciprocal shareholding		(154.3	)		(135.7	)

		5,112.7			4,610.6

		19,090.8			18,379.3

See accompanying notes to the unaudited consolidated financial statements.

-5-

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP). These consolidated financial statements do not include all disclosures required for annual financial statements and therefore should be read in conjunction with the consolidated financial statements and notes thereto included in Enbridge Inc.’s 2006 Annual Report. These accounting principles are different in some respects from United States generally accepted accounting principles (U.S. GAAP) and the significant differences that impact the Company’s financial statements are described in Note 5. These interim financial statements follow the same significant accounting policies and methods of application as those included in the 2006 Annual Report, except as described in Note 1.

Earnings for interim periods may not be indicative of results for the fiscal year due to the seasonal nature of the gas distribution utility business and other factors.

Certain comparative amounts have been reclassified to conform to the current year’s presentation.

1. CHANGES IN ACCOUNTING POLICIES

Financial Instruments, Comprehensive Income and Hedging Relationships

Effective January 1, 2007, the Company adopted new accounting standards for Financial Instruments - Recognition and Measurement, Financial Instruments — Disclosure and Presentation, Comprehensive Income, and Hedges. These policies were adopted prospectively and accordingly, the prior periods were not restated, however unrealized gains and losses related to the Company’s foreign currency translation adjustments and net investment hedges are now included in Accumulated Other Comprehensive Income or Loss (AOCI).

The adoption of the new standards did not impact the Company’s earnings or cash flows.

Financial Instruments

Measurement and Presentation

The new standards require that all financial assets and liabilities are recorded at fair value, except loans and receivables and certain instruments held to maturity, which are measured at amortized cost. For instruments measured at fair value, unrealized changes in fair value are recognized in earnings, unless the instrument is an available for sale asset or is an effective hedge and is designated as a cash flow hedging instrument, in which case the unrealized changes are recorded in Other Comprehensive Income.

With the exception of recognizing derivative instruments, including hedge instruments, at fair value, the Company has not changed the valuation of other financial instruments.

The Company utilizes fixed price forward physical commodity contracts to manage exposure to changes in commodity prices. Certain of the fixed price contracts are deemed derivative instruments and therefore are recognized at fair value. Unrealized fair value changes related to these instruments are recorded in current earnings. The Company’s Energy Services businesses had an unrealized gain of $0.6 million (after tax) and an unrealized loss of $3.9 million (after tax) for the three and nine months ended September 30, 2007 related to fixed price commodity purchases and sales.

-6-

The Company’s regulated liquids pipeline segment utilizes a fixed price contract and related financial instrument to manage the mix of fixed and floating power costs. The Company recognizes the fair value of the fixed price contract, the fair value of the financial instrument and a regulatory liability that will be recognized over the life of the fixed price contract.

As a result of the new standards for derivative instruments, on January 1, 2007, the Company recognized a liability of $5.8 million for unrealized financial instrument losses, an asset of $29.0 million related to the fixed price power contracts and a regulatory liability of $23.2 million. At September 30, 2007, the Company recognized a liability of $8.3 million for unrealized financial instrument losses, an asset of $39.2 million related to the fixed price power contract and a regulatory liability of $30.9 million.

Transaction Costs

On January 1, 2007, the Company reclassified unamortized deferred financing fees of $52.7 million from deferred amounts and other assets to long-term debt as a result of adopting the new standards. The reclassification of debt issue costs has no impact on earnings. Financing fees are amortized using the effective interest rate method over the life of the related debt instrument.

Comprehensive Income

The new standards also require the Company to present Consolidated Statements of Comprehensive Income which consist of earnings; the effective portion of changes in unrealized gains and losses related to cash flow hedges; unrealized gains and losses on available for sale assets; and unrealized foreign exchange gains and losses related to self sustaining foreign investments and the net investment hedges of those foreign investments. The cumulative changes in Comprehensive Income are recorded in AOCI, a separate component of shareholders’ equity. AOCI also includes the Company’s share of the AOCI of equity investees. Unrealized gains and losses included in AOCI are reclassified to earnings when they become realized in accordance with hedge accounting standards or in the case of available for sale assets when they are sold.

Hedges

The Company utilizes derivatives and non-derivative instruments to manage changes in commodity prices, foreign currency exchange rates and interest rates. Hedge accounting continues to be optional, and it requires that the Company document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. The Company presents the earnings and cash flow effects of hedging items with the hedged transaction.

Cash Flow Hedges

The Company utilizes cash flow hedges to manage changes in commodity prices, foreign currency exchange rates and interest rates. The effective portion of the change in fair value of the cash flow hedging instrument is recorded in other comprehensive income and reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings.

For the Company’s regulated gas distribution businesses, a portion of the gas purchases have been hedged using cash flow hedges on behalf of the ratepayers. The effective portion of changes in the fair value of the cash flow hedges are deferred as an asset or liability until they are settled and an offsetting asset or liability is recorded. Upon settlement, the recognized gain or loss is refunded to or collected from ratepayers in subsequent period rates. The Company recognized a liability of $26.6 million for unrealized losses related to gas purchase hedges for regulated gas distribution businesses at January 1, 2007, and a regulatory receivable of $26.6 million. Pursuant to the Ontario Energy Board’s final decision issued July 5, 2007 regarding EGD’s 2007 rate application directing EGD to cease its risk management program, EGD no longer utilizes derivative and non-derivative instruments to manage changes in commodity prices, effective July 2007. However any instruments entered into before the decision was issued are allowed to complete their contractual term.

-7-

As a result of the new standards for cash flow hedges, the Company recognized a net asset of $79.4 million for unrealized net gains related to interest rate, foreign exchange and commodity hedges at January 1, 2007. The Company reduced both deferred amounts and retained earnings by $66.1 million (pre-tax) for historical fair value adjustments related to certain cash flow hedges.

If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred and recognized concurrently with the related transaction. If the anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from ineffective derivative instruments are recognized in earnings in the period they occur. During the nine month period ended September 30, 2007, the Company terminated interest rate forwards relating to anticipated debt issuances that were no longer required resulting in the recognition of a $1.1 million (after tax) gain.

The Company does not use derivative instruments for speculative purposes. However, if a derivative instrument is not an effective hedge for accounting purposes or is not designated as a hedging item, changes in the fair value are recorded in current period earnings. The Company recognized net unrealized mark to market derivative losses of $6.3 million (after tax) and $12.6 million (after tax) for the three and nine months ended September 30, 2007 related to non-qualifying instruments.

At September 30, 2007, the Company has a net asset of $173.1 million for the unrealized fair value of effective cash flow hedges. Cash flow hedges expire over periods ranging from less than one year to 22 years. The Company estimates that $1.7 million (after tax) of the AOCI will be reclassified to earnings in the next 12 months.

Fair Value Hedges

The Company may utilize fair value hedges to hedge the fair value of debt instruments or commodity positions. The change in fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability ceases to be remeasured to fair value, and the fair value adjustment is recognized in earnings over the remaining life of the hedged item. If the hedged item is settled, any remaining fair value adjustment is recognized immediately in earnings. As at September 30, 2007, the Company did not have any outstanding fair value hedges.

Net Investment Hedges

The Company utilizes net investment hedges to manage the carrying values of U.S. Dollar and Euro denominated foreign investments. The effective portion of the change in the fair value of the hedging instrument is recorded in other comprehensive income. Any ineffectiveness is recorded in current period earnings. Amounts recognized in AOCI are recognized in earnings when there is reduction of the hedged net investment resulting from a sale of ownership interests. At September 30, 2007, the Company recognized a net asset of $568.1 million related to net investment hedges. Net investment hedges expire over periods ranging from less than one year to 15 years.

-8-

The adoption of the new standards resulted in the following adjustments on January 1, 2007:



(millions of Canadian dollars)	January 1, 2007
				Liabilities
Increase/(Decrease)	Assets			and Equity


Accounts Receivable and Other		5.4			—
Deferred Amounts and Other Assets		55.3			—
Long-Term Investments		(57.3	)		—
Accounts Payable and Other		—			57.6
Long-Term Debt		—			(52.7	)
Other Long-Term Liabilities		—			42.5
Future Income Taxes		—			(18.9	)
Non-Controlling Interest		—			(26.3	)
Accumulated Other Comprehensive Income		—			48.2
Retained Earnings		—			(47.0	)

		3.4			3.4

Components of Accumulated Other Comprehensive Income/(Loss)


									Cumulative
	Cash Flow			Equity			Non-Controlling		Translation			Net Investment
(millions of Canadian dollars)	Hedges			Investees			Interests		Adjustment			Hedges			Total


Balance at January 1, 2006		—			—			—		(486.7	)		428.1			(58.6	)
Tax impact		—			—			—		—			(113.2	)		(113.2	)

		—			—			—		(486.7	)		314.9			(171.8	)

Changes during the period		—			—			—		(89.3	)		54.7			(34.6	)
Tax impact		—			—			—		—			(11.1	)		(11.1	)

		—			—			—		(89.3	)		43.6			(45.7	)

Balance at September 30, 2006		—			—			—		(576.0	)		358.5			(217.5	)


Balance at January 1, 2007		—			—			—		(399.1	)		379.1			(20.0	)
Tax impact		—			—			—		—			(115.8	)		(115.8	)

		—			—			—		(399.1	)		263.3			(135.8	)

Adjustment on adoption		79.4			(57.3	)		26.3		—			—			48.4
Tax impact		(20.3	)		20.1			—		—			—			(0.2	)

		59.1			(37.2	)		26.3		—			—			48.2

Changes during the period		93.7			(6.9	)		1.2		(443.5	)		189.0			(166.5	)
Tax impact		(25.8	)		2.4			—		—			(22.2	)		(45.6	)

		67.9			(4.5	)		1.2		(443.5	)		166.8			(212.1	)

Balance at September 30, 2007		127.0			(41.7	)		27.5		(842.6	)		430.1			(299.7	)

Capital Disclosures and Financial Instruments — Disclosure and Presentation

Effective January 1, 2008, the Company will adopt new accounting standards for Capital Disclosures and Financial Instruments — Disclosure and Presentation. The Company will disclose its objectives, policies and procedures for managing capital, additional information with respect to capital compliance requirements and enhanced disclosure of risks associated with financial instruments, as well as how those risks are managed.

-9-

2. SEGMENTED INFORMATION

Three months ended September 30, 2007

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services

International

Corporate

Consolidated

Revenues

266.7

76.3

65.0

2,224.1

1.9

—

2,634.0

Commodity costs

—

(2,004.6

)

—

(2,004.6

)

Operating and administrative

(110.0

)

(23.6

)

(19.4

)

(129.7

)

(3.2

)

(4.1

)

(290.0

)

Depreciation and amortization

(39.6

)

(20.0

)

(17.8

)

(71.4

)

(0.2

)

(2.0

)

(151.0

)

117.1

32.7

27.8

18.4

(1.5

)

(6.1

)

188.4

Income from equity investments

(0.3

)

—

28.0

(11.5

)

15.6

(0.4

)

31.4

Other investment income

4.0

1.2

1.0

5.2

9.0

4.5

24.9

Interest and preferred share dividends

(27.3

)

(15.9

)

(15.4

)

(51.5

)

—

(27.2

)

(137.3

)

Non-controlling interests

(0.4

)

—

(7.7

)

(1.6

)

—

(9.7

)

Income taxes

(30.7

)

(6.1

)

(12.3

)

16.3

(0.5

)

13.7

(19.6

)

Earnings applicable to common shareholders

62.4

11.9

21.4

(24.7

)

22.6

(15.5

)

78.1


Three months ended September 30, 2006

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

Revenues		254.7			87.2			60.8			1,778.4			3.8			—			2,184.9
Commodity costs		—			—			—			(1,562.4	)		—			—			(1,562.4	)
Operating and administrative		(93.7	)		(24.6	)		(13.4	)		(113.5	)		(4.7	)		(6.7	)		(256.6	)
Depreciation and amortization		(35.8	)		(23.5	)		(17.5	)		(66.7	)		(0.3	)		(1.6	)		(145.4	)

		125.2			39.1			29.9			35.8			(1.2	)		(8.3	)		220.5
Income from equity investments		0.2			—			31.1			(9.3	)		13.9			—			35.9
Other investment income		1.9			2.3			0.4			4.9			9.9			13.8			33.2
Interest and preferred share dividends		(24.8	)		(18.0	)		(14.7	)		(48.9	)		—			(37.5	)		(143.9	)
Non-controlling interests		(0.5	)		—			(11.3	)		(1.6	)		—			—			(13.4	)
Income taxes		(33.9	)		(8.3	)		(13.5	)		7.7			(1.5	)		12.7			(36.8	)

Earnings applicable to common shareholders		68.1			15.1			21.9			(11.4	)		21.1			(19.3	)		95.5

-10-

Nine months ended September 30, 2007

Gas

Liquids

Gas

Sponsored

Distribution

(millions of Canadian dollars)

Pipelines

Investments

and Services

International

Corporate

Consolidated

Revenues

798.6

241.4

197.8

7,476.3

6.8

—

8,720.9

Commodity costs

—

(6,583.4

)

—

(6,583.4

)

Operating and administrative

(312.4

)

(64.7

)

(56.7

)

(388.7

)

(10.4

)

(12.0

)

(844.9

)

Depreciation and amortization

(117.5

)

(64.3

)

(55.9

)

(207.5

)

(0.7

)

(4.1

)

(450.0

)

368.7

112.4

85.2

296.7

(4.3

)

(16.1

)

842.6

Income from equity investments

(0.7

)

—

72.2

(3.5

)

44.8

(1.0

)

111.8

Other investment income

7.7

18.3

37.8

13.3

30.1

26.3

133.5

Interest and preferred share dividends

(77.1

)

(50.1

)

(45.9

)

(152.0

)

—

(89.4

)

(414.5

)

Non-controlling interests

(1.1

)

—

(28.8

)

(4.8

)

—

(34.7

)

Income taxes

(100.4

)

(29.6

)

(47.9

)

(41.3

)

(2.0

)

34.1

(187.1

)

Earnings applicable to common shareholders

197.1

51.0

72.6

108.4

68.6

(46.1

)

451.6

Nine months ended September 30, 2006



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

Revenues		748.6			260.3			186.2			6,654.6			9.1			—			7,858.8
Commodity costs		—			—			—			(5,850.0	)		—			—			(5,850.0	)
Operating and administrative		(263.7	)		(71.7	)		(46.3	)		(352.4	)		(12.5	)		(13.3	)		(759.9	)
Depreciation and amortization		(114.5	)		(65.9	)		(53.5	)		(198.8	)		(0.7	)		(4.2	)		(437.6	)

		370.4			122.7			86.4			253.4			(4.1	)		(17.5	)		811.3
Income from equity investments		0.1			—			85.3			8.3			40.3			—			134.0
Other investment income		2.9			8.3			2.1			15.3			35.6			19.2			83.4
Interest and preferred share dividends		(75.6	)		(55.3	)		(44.7	)		(143.7	)		—			(103.1	)		(422.4	)
Non-controlling interests		(1.4	)		—			(41.3	)		(3.9	)		—			—			(46.6	)
Income taxes		(93.4	)		(28.7	)		(22.5	)		(20.8	)		(7.6	)		57.6			(115.4	)

Earnings applicable to common shareholders		203.0			47.0			65.3			108.6			64.2			(43.8	)		444.3

Additions to Property, Plant and Equipment

Three months ended

Nine months ended

September 30,

(millions of Canadian dollars)

2007

2006

2007

2006

Liquids Pipelines

471.3

54.0

931.6

190.9

Gas Pipelines

44.5

21.1

161.3

80.7


	September 30, 2007						December 31, 2006
				United						United
(millions of Canadian dollars)	Canada			States			Canada			States

Assets
Cash and cash equivalents^2,5		170.9			311.7			139.7			347.0
Accounts receivable and other^2,3,5		2,046.7			2,551.6			2,045.6			2,920.0
Inventory^2,5		867.0			991.6			868.9			1,005.0

		3,084.6			3,854.9			3,054.2			4,272.0
Property, plant and equipment, net^2,5		12,037.0			17,066.2			11,264.7			15,628.4
Long-term investments^2,5		2,098.2			1,254.1			2,299.4			1,368.8
Deferred amounts and other assets^1,2,3,4,5		1,063.7			1,736.6			924.5			1,540.5
Intangible assets⁵		215.4			312.4			241.5			348.0
Goodwill⁵		381.7			730.8			394.9			803.2
Future Income taxes⁵		210.2			210.4			200.1			200.1

		19,090.8			25,165.4			18,379.3			24,161.0

Liabilities and Shareholders’ Equity
Short-term borrowings		570.8			570.8			807.9			807.9
Accounts payable and other^2,3,5		2,022.0			2,760.5			1,723.8			2,818.6
Interest payable⁵		98.8			132.1			95.1			108.4
Current maturities and short-term debt⁵		452.7			626.2			537.0			537.0
Current maturities of non-recourse debt^2,5		56.8			56.6			60.1			83.2

		3,201.1			4,146.2			3,223.9			4,355.1
Long-term debt³		7,295.7			9,865.3			7,054.0			7,054.0
Non-recourse long-term debt^2,5		1,520.9			1,520.9			1,622.0			4,029.6
Other long-term liabilities^2,4,5		278.3			496.0			91.1			310.8
Future income taxes ^1,2,3,4,5		1,030.0			1,650.2			1,062.5			1,696.4
Non-controlling interests⁵		652.1			2,433.2			715.2			2,163.9

		13,978.1			20,111.8			13,768.7			19,609.8

Shareholders’ Equity
Preferred shares		125.0			125.0			125.0			125.0
Common shares		3,017.8			3,017.8			2,416.1			2,416.1
Contributed surplus		25.2			—			18.3			—
Retained earnings		2,398.7			2,365.8			2,322.7			2,242.8
Additional paid in capital		—			69.1			—			62.2
Foreign currency translation adjustment³		—			—			(135.8	)		—
Accumulated other comprehensive loss^3,4		(299.7	)		(369.8	)		—			(159.2	)
Reciprocal shareholding		(154.3	)		(154.3	)		(135.7	)		(135.7	)

		5,112.7			5,053.6			4,610.6			4,551.2

		19,090.8			25,165.4			18,379.3			24,161.0