GAS DISTRIBUTION AND SERVICES

Gas Distribution and Services consists of gas utility operations which serve residential, commercial, industrial and transportation customers, primarily in Central and Eastern Ontario, the most significant being Enbridge Gas Distribution (EGD). It also includes natural gas distribution activities in Quebec, New Brunswick and New York State, the Company’s investment in Aux Sable, a natural gas fractionation and extraction business, and the Company’s commodity marketing businesses.

Earnings were $178.2 million for the year ended December 31, 2006 compared with $178.8 million for the year ended December 31, 2005. Earnings were comparable with 2005, reflecting a number of offsetting factors including higher earnings from the Aux Sable natural gas fractionation facility due to upside sharing of positive fractionation margins under a new arrangement with BP and lower earnings from EGD resulting from warmer than normal weather and a lower allowed rate of return on common equity.

Earnings were $178.8 million for the year ended December 31, 2005 compared with $313.1 million for the year ended December 31, 2004. The 2004 earnings included 15 months of operations from the gas distribution operations as a result of the change in EGD’s fiscal year end. Earnings for 2004 also included an after-tax gain of $97.8 million on the sale of the investment in AltaGas Income Trust.

Revenues for the year ended December 31, 2006 were $8,981.6 million compared with $6,947.1 million for the year ended December 31, 2005. The factors contributing to this increase were Tidal Energy commencing US operations in December 2005, resulting in a full year of revenues captured in 2006, as well as Tidal Energy earning higher revenues due to a higher average price of crude oil in 2006 and EGD’s revenues increasing over 2005, as gas prices were high in Q1 of 2006, when the greatest sales volumes were generated.

Revenues for the year ended December 31, 2005 were $6,947.1 million compared with $6,631.1 million for the year ended December 31, 2004. Revenues increased due primarily to increased commodity prices in Tidal which is included in Other

Enbridge Gas Distribution
EGD is a rate-regulated natural gas distribution utility serving customers in its franchise areas of central and eastern Ontario, including the City of Toronto and surrounding areas as well as the Niagara Peninsula, Ottawa and many other Ontario communities. EGD is Canada’s largest natural gas distribution company and has been in operation for more than 150 years. It serves over 1.8 million customers in central and eastern Ontario, Southwestern Quebec, and parts of Northern New York State. EGD’s operations in Ontario are regulated by the Ontario Energy Board (OEB).

Results of Operations
Earnings for the year ended December 31, 2006 were $61.8 million compared with $111.9 million for the year ended December 31, 2005. Warmer than normal weather in 2006 reduced earnings by $36.9 million compared with relatively normal weather in 2005 which did not significantly impact earnings. EGD earnings were also reduced by a lower allowed rate of return on common equity, partially offset by a higher rate base. EGD’s earnings are also affected by variances from the forecast cost of service, including operating and maintenance costs. EGD’s costs can vary due to many factors including weather, project timelines and the timing of operating and capital expenditures.

Earnings for the year ended December 31, 2005 were $111.9 million compared with $133.1 million for the year ended December 31, 2004. Earnings for the year ended December 31, 2004 included 15 months of earnings for EGD, as a result of the elimination of the quarter lag basis of consolidation. Earnings for the extra quarter, the three months ended December 31, 2003, were $11.5 million. Weather in 2004 was colder than normal resulting in an additional $21.3 million in earnings. The remaining EGD variance is the result of a higher rate base and a number of smaller positive variances across the utility in 2005.

Normal weather is the weather forecast by EGD in its annual rates application, in the Toronto area, including the impacts of both the long run and short run actual historical weather experience, more heavily weighted on the short run experience, and is subject to OEB approval. This financial measure is unique to EGD and, due to differing franchise areas, is unlikely to be directly comparable to the impact of weather-normalized factors that may be identified by other companies. Moreover, normal weather may not be comparable year-to-year given that the forecasting model weights the degree-days from the most recent years more heavily to determine the estimate. This weather-normalized adjustment method is the same as the manner in which EGD calculates degree-days for regulatory purposes.

2007 Rate Application
In August 2006, EGD filed an application with the OEB for approval of the 2007 rates, under a cost of service rate-making methodology. In January 2007, EGD arrived at an agreement to settle certain major issues inn its rate application with key stakeholders. This settlement was approved by the OEB on January 29, 2007 and will allow EGD to continue operating within its current environment. A final decision on this rate application is expected during the second quarter of 2007. As part of its 2007 rate application, EGD has requested an increase in the equity component of its deemed capital structure for regulatory purposes. The requested 38% equity level reflects changes in EGD’s current business risk environment and financial risk position relative to the current approved deemed equity level of 35%. The rate of return on common equity is calculated with reference to a formula approved by the OEB that incorporates the long bond yield forecast. The rate of return of 8.74% was used in the 2007 rate application as a placeholder and reflected the OEB approved return embedded within 2006 rates. The allowed return on equity for 2007, calculated in accordance with OEB formula is 8.39%. This rate of return on common equity will replace the placeholder used by the Company in its 2007 rate application and will be embedded in 2007 rates.

Given the OEB’s scheduled plan to move to Incentive Regulation, the Company expects 2007 to become the base year for a potential four to five year rate capped plan. The details of such plan are expected to be known in 2007. A description of Incentive Regulation is included below under “Strategy”.

The key elements of the 2007 application and the 2006 and 2005 decisions are summarized below:

The OEB released its decision relating to EGD’s 2006 rate application on February 9, 2006. The new rates approved by the OEB’s decision resulted in an overall increase in rates of approximately 1% for the average residential customer.

2006 and 2005 Rates
EGD’s 2006 and 2005 rates were established pursuant to a cost of service methodology that allowed revenues to be
set to recover EGD’s forecast costs. Forecast costs included gas commodity and transportation, operation and maintenance, depreciation, income taxes, and the debt and equity costs of financing the rate base. The rate base is EGD’s investment in all assets used in gas distribution, storage and transmission, as well as an allowance for working capital. Under the cost-of-service model, it is EGD’s responsibility to demonstrate to the OEB the prudence of the forecast costs.

The rate base is financed through a combination of debt and equity. The proportion of debt and equity, currently 65% and 35% respectively, is approved by the OEB. For the debt portion, interest expense incurred by the Company is recovered in rates. For the equity portion, the OEB sets the rate of return that EGD may recover in rates. The allowed rate of return on equity for EGD is based on the forecast yield on Canadian government long-term bonds.

For 2004, rates were set by increasing 2003 rates by 90 percent of the forecast Ontario consumer price index, resulting in an increase of 1.8 percent. The OEB also added a sharing mechanism to fiscal 2004, whereby if earnings on a weather-normalized basis exceeded the benchmark ROE, these excess earnings would be shared on a 50/50 basis between ratepayers and the Company’s shareholders.

Effects of Rate Regulations
EGD is subject to rate-regulation, therefore there are circumstances where the revenues recognized do not match the amounts billed. Certain amounts are deferred for recovery or refund with the approval of the regulator and are not included in revenues or expenses that would otherwise be recognized in the income statement, in the absence of rate regulation. The regulator, allows certain variances between approved and actual expenses to be recovered from, or refunded to, customers in future periods. The deferred amounts are not included in the calculation of rates billed to customers. While there are numerous deferral accounts approved by the regulator, the difference between the price of gas approved by the regulator and the actual cost of gas purchased is the most significant such example. On refund or recovery of this difference, no earnings impact is recorded. Effectively, the income statement captures only the approved cost of gas and the related revenue rather than the actual cost of gas and related revenue. EGD has no exposure to changes in the cost of gas, as it is a flow through cost that is passed to the ratepayer.

Strategy
EGD’s vision is to be North America’s leading energy distribution company, providing safe and reliable distribution services to customers at fair and reasonable costs. To achieve this vision, EGD has outlined the following strategic objectives:

	to continue growth of the business through enhancement of infrastructure and storage facilities;
	improve opportunities for better returns through Incentive Regulation, which is expected to start in 2008;
	to be best-in-class in the safe and reliable operation of its gas distribution system;
	to be a leader in utility asset management; and
	enhance customer satisfaction by meeting customer commitments and enhancing value of services

Customer Growth
A major strategic initiative is enhancing customer growth. EGD added over 47,000 new customers in the year ended December 31, 2006 (over 50,000 in the year ended December 31, 2005). The Company expects to continue to add 45,000-50,000 customers in 2007. New growth areas relating to construction heat, mass markets and distributed energy are also being pursued as part of a profitable utility growth portfolio. EGD will also lead research and development efforts into longer-term promising technologies that have the potential to retain and increase gas load and reduce operating costs while providing customer benefits. EGD has been successful in pursuing its industry facilitation strategy with the recent launch of “EnergyLink”, a web-based tool that makes it easier for customers to find and install natural gas appliances.

Incentive Regulation
Improving the regulatory environment is also a key strategic thrust to provide greater operational and organizational flexibility. EGD will remain in a cost of service environment in 2007 but a change to Incentive Regulation (IR), is expected in 2008, with 2007 as the base year for a potential four to five year plan. Consultation with the OEB has commenced with respect to potential implementation of IR methodology for setting rates for services provided by EGD, which differs from the existing cost of service methodology. The potential impact on the future operating environment of EGD is not currently known, however EGD expects to obtain details on a proposed IR plan in the fourth quarter of 2007.

The following are the key anticipated parameters of IR:

	Inclusion of an appropriate annual adjustment mechanism to give effect to cost changes and productivity improvements, to ensure that benefits of efficiencies are shared with customers during the term of the plan;
	Mandatory cost of service rebasing at the end of each IR plan term and before a new plan is put in place to ensure that efficiency improvements will be identified and the benefits are passed onto customers through base rates for the following IR plan period;
	Earnings sharing mechanisms will not form part of IR plans, in order to provide a strong incentive to achieve sustainable efficiencies that can be shared with customers through the annual adjustment mechanism and rebasing; and
	IR term plans are expected to run between four and five years.
The objectives of IR are as follows:
	Reduce regulatory costs with less frequent hearings (maximum every 4 to 5 years) rather than every year under the current cost of service mechanism;
	Provide incentives for improved efficiency;
	Provide more flexibility for utility management; and
	Provide more stables rates.

Capital Expenditures
EGD’s capital expenditures in recent years have averaged approximately $300 million per year. The capital expenditure budget is approved annually by the OEB, under the current cost of service environment.

Legal Proceedings
Class Action Lawsuit - late payment penalties
In July 2006, culminating a 12-year legal case, EGD entered into a settlement agreement with respect to the repayment of a portion of amounts paid to it as late payment penalties. The total amount of late payment penalties billed between April 1994 and February 2002, when the late payment penalty was revised, was approximately $74 million.

Under a settlement agreement approved by the Ontario Superior Court of Justice (the Court) in December 2006, EGD will contribute $9 million to the Winter Warmth Fund (WWF), pay class counsel approximately $10 million for the plaintiff’s legal fees and expenses and pay approximately $2 million to the Class Proceedings Fund. The WWF provides eligible low-income customers of participating Ontario utilities with financial assistance for the payment of their natural gas and electricity bills. In accordance with the settlement agreement, EGD paid $2 million to class counsel shortly after the settlement agreement was executed, which amount was held in trust by class counsel until the settlement became final. EGD paid the remaining settlement amount of approximately $19 million in January 2007. EGD has recorded a receivable from ratepayers for the total amount of $21 million and will apply to the OEB for recovery of payments resulting from the settlement.

Bloor Street Incident
EGD has been charged under both the Ontario Technical Standards and Safety Act (TSSA) and the Ontario Occupational Health and Safety Act (OHSA) in connection with an explosion that occurred on Bloor Street West in Toronto on April 24, 2003. The maximum possible fine upon conviction on all charges would be $5.0 million in aggregate. EGD 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 has also been called, but the proceedings are stayed pending resolution of the TSSA and OHSA matters. The courts have not yet ruled upon any of the charges laid under the TSSA or the OHSA, and thus it is not possible at this time to predict or comment upon the potential outcome. The trial in respect of these charges commenced January 3, 2006 and is not expected to be completed until well into 2007, at the earliest. EGD does not expect the outcome of these civil actions to result in any material financial impact.

Business Risks
The risks identified below are specific to EGD. General risks that affect the Company as a whole are described under Risk Management.

The business risks inherent in the natural gas distribution industry impact the ability of EGD to realize the revenue level required to generate the allowed return on equity. These business risks include obtaining timely and adequate rate relief, as well as accuracy in forecasting and realizing natural gas distribution volumes.

Volume Risks
Since customers are billed on a volumetric basis, the ability to collect the total revenue requirement (the cost of providing service) depends on achieving the forecast distribution volume established in the annual ratemaking process. The probability of realizing such volume is contingent upon weather; economic conditions; the price of gas relative to competitive energy sources; and the number of customer additions.

Sales and transportation of gas for customers in the residential and commercial sectors account for approximately 77% (2005 – 78%) of total distribution volume. Weather during the year, measured in degree days, has a significant impact on distribution volume as a major portion of the gas distributed to these two markets is used ultimately for space heating. In 2006, the winter months were warmer than forecast, resulting in an unfavourable weather related volume variance of 27.4 bcf.

Distribution volume may also be impacted by the increased adoption of energy efficient technologies along with more efficient building construction that continues to place downward pressure on annual average consumption. Average annual gas usage has declined by 1.2% per annum over the last 10 years, reflecting consistent customer conservation efforts.

Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volumes distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions are important to all market sectors as continued expansion adds to the total consumption of natural gas.

Earnings from EGD are impacted to the extent that volumes sold differ from forecasted volumes. Key factors that affect the probability that EGD will distribute the forecast volumes include weather, economic conditions, gas prices and the prices of competing energy sources and the number of customers added. To the extent that these factors vary unfavourably compared with forecasts, EGD will not achieve the total revenue requirements established in the ratemaking process due to lower distribution volumes, thus resulting in lower earnings.

Distribution volume may also be impacted by the increased adoption of energy efficient technologies along with more efficient building construction that continues to place downward pressure on annual average consumption.

Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn the approved return on equity due to other forecast variables such as the mix between the higher margin residential and commercial sectors, and lower margin industrial sector.

Rate Relief
The OEB has in the past, rendered decisions that have disallowed recovery of certain costs incurred by EGD. Through the regulatory process, the OEB approves the return on equity, which EGD is allowed to earn, in addition to various other aspects of utility operations.

Rate relief could be pursued for significant unforecasted amounts allowing EGD to recover the costs of providing and maintaining the quality of its service while achieving the allowed rate of return on rate base.

Forecasting Accuracy
EGD is exposed to forecasting accuracy risk as rates are established in advance, based on anticipated distribution volume by class of customer. Forecasts are also made for the future costs of debt and equity capital including the forecast yield rate for long-term Government of Canada Bonds used in the determination of the return on equity. Through the forecasting process, it is intended that any changes in cost of service, regardless of whether they are caused by inflation or by level of business activity, would be reflected in new rates applied for in the upcoming fiscal year.

Franchise Rights
EGD has an exclusive right to serve all end users within its franchise area, under its franchise agreements. Similar franchise agreements in adjacent areas are held by peer companies such as Union Gas Limited (UGL). On January 6, 2006, the OEB granted Greenfield Energy Corporation, a potential power-plant customer of UGL, the right to physically bypass UGL’s distribution network within UGL’s franchise area, in order to serve its own power-plant. The OEB's decision to not uphold exclusive franchise rights of a local distribution utility in Ontario was unprecedented. However, the OEB characterized this decision as transitional, and set up a rates proceeding which assessed the service requirements of gas fired generation in the province of Ontario. The OEB decision from this rates proceeding was issued in November 2006. EGD believes the new rates are robust and would make physical bypass of EGD’s system unattractive to gas fired power generation plants. However, the OEB decision did not preclude any party from seeking approval from the OEB to build its own pipeline and bypass the local distribution utility. EGD objects strongly to the concept that any such franchise violation is acceptable and will object should any similar proposal arise in the EGD franchise area.

Noverco
Enbridge owns an equity interest in Noverco through ownership of 32% of the common shares and a cost investment
in preferred shares. Noverco is a holding company that owns approximately 71% of Gaz Metro Limited Partnership
(Gaz Metro), a gas distribution company operating in the province of Quebec and the state of Vermont. Gaz Metro also has a 50% interest in TQM Pipeline, which transports natural gas in Quebec, and is partnering with the Company on the Rabaska LNG project (described under “Strategy” below).

Noverco also has an investment in the common shares of Enbridge resulting in dividend and earnings elimination adjustments at Enbridge. Noverco receives dividends from Enbridge but because Enbridge owns part of Noverco, a portion of the dividends Noverco receives are effectively dividends that Enbridge has paid to itself. This portion of the dividends paid reduces the book value of Enbridge’s investment in Noverco.

Results of Operations
Noverco earnings were $22.7 million for the year ended December 31, 2006 compared with $28.3 million for the year ended December 31, 2005. Earnings decreased due to a $7.3 million dilution gain in 2005, which resulted from a Gaz Metro LP unit issuance in which Noverco did not participate, compared with a dilution gain of $4.0 million in 2006. Excluding dilution gains, earnings from Noverco were lower in 2006 as the prior year included a future income tax recovery stemming from the receipt of a significant cash dividend.

Noverco earnings were $28.3 million for the year ended December 31, 2005 compared with $32.3 million for the year ended December 31, 2004. The 2005 results included the $7.3 million dilution gain within Noverco on unit issuances by Gaz Metro. The 2004 results included 15 months of earnings as a result of the elimination of the quarter lag basis of consolidation. Earnings for the extra quarter, the three months ended December 31, 2003, were $13.6 million. The remaining variance reflected the future income tax recovery related to the receipt of cash dividends net of an adjustment for reciprocal dividends.

Weather variations do not affect Noverco’s earnings as Gaz Metro is not exposed to weather risk. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investment, which is based on the yield of 10-year Government of Canada bonds plus 4.34%.

CustomerWorks/ECS
CustomerWorks/ECS includes the operations of CustomerWorks and Enbridge Commercial Services (ECS). CustomerWorks is 70% owned by Enbridge and provides customer care services, including billing, collections, and operation of call centers primarily for; EGD, Direct Energy Essential Home Services and Terasen Gas (a gas distribution company in British Columbia). EGD is currently reviewing its customer care provider and expect to conclude this process in mid-2007. ECS owns the customer information services system that CustomerWorks uses under license to provide services to EGD.

Enbridge Gas New Brunswick
The Company owns 70% of, and operates, Enbridge Gas New Brunswick (EGNB), which owns the natural gas distribution franchise in the province of New Brunswick. EGNB is constructing a new distribution system and has approximately 5,600 customers. Approximately 565 kilometres (351 miles) of distribution main has been installed with the capability of attaching approximately 27,000 customers.

EGNB earnings were $9.8 million for the year ended December 31, 2006 compared with $6.1 million for the year ended December 31, 2005. Earnings were higher in 2006 as debt was settled through the issuance of equity, during the third and fourth quarters of 2005 resulting in a higher equity base throughout 2006.

Enbridge Gas New Brunswick earnings were $6.1 million for the year ended December 31, 2005 compared with $3.7 million for the year ended December 31, 2004. The increase is consistent with the settlement of debt through the issue of equity in 2005, resulting in a higher equity base.

EGNB is regulated by the New Brunswick Board of Commissioners of Public Utilities (PUB). As it is currently in the development period, EGNB’s cost of service exceeds its distribution revenues. The PUB has approved the deferral of the difference between distribution revenues and the cost of service during the development period for recovery in future rates. This recovery period is expected to start in 2010 and end no sooner than December 31, 2040. On December 31, 2006, the regulatory deferral asset was $101.8 million (2005 – $82.7 million).

Other Gas Distribution Operations
Earnings from Other Gas Distribution Operations were $6.5 million consistent with $6.7 million for the year ended December 31, 2005.

Earnings from Other Gas Distribution Operations decreased $1.8 million in 2005, primarily because the 2004 results included 15 months of earnings as a result of the elimination of the quarter lag basis of consolidation. Earnings for the extra quarter, the three months ended December 31, 2003, were $2.0 million.

Aux Sable
Enbridge owns 42.7% of Aux Sable, a natural gas liquids (NGL) extraction and fractionation business near Chicago. Aux Sable owns and operates a plant, at the terminus of the Alliance System. The plant extracts NGL from the energy-rich natural gas transported on the Alliance System, as necessary, to meet the heat content requirements of local distribution companies, which require natural gas with less NGL, or lower heat content, and to take advantage of positive commodity price spreads.

Aux Sable has an agreement with BP Products North America Inc. to sell its NGL production to BP. In return, BP pays Aux Sable a fixed annual fee and a share of any net margin generated from the business in excess of specified natural gas processing margin thresholds. In addition, BP compensates Aux Sable for all operating, maintenance and capital costs associated with the Aux Sable facilities subject to certain limits on capital costs. BP supplies, at its cost, all make-up gas and fuel supply gas to the Aux Sable facilities and is responsible for the capacity on the Alliance Pipeline held by an Aux Sable affiliate, at market rates. The agreement is for an initial term of 20 years, commencing January 1, 2006 and may be extended by mutual agreement for 10-year terms. If cumulative losses exceed a certain limit, BP will have the option to terminate the agreement, however Aux Sable has the right to reduce such losses to avoid termination.

Earnings for the year ended December 31, 2006 were $25.8 million compared with earnings of $5.3 million for the year ended December 31, 2005. Fractionation margins were very positive throughout 2006 and as a result, earnings from the upside sharing mechanism account for the majority of earnings from Aux Sable.

Fractionation margins are expected to moderate but remain favourable in 2007, given high oil prices and relatively low gas prices.

Earnings for the year ended December 31, 2005 were $5.3 million compared with earnings of $7.3 million for the year ended December 31, 2004. The decrease was due to higher natural gas costs in 2005, which were not offset by product sales prices causing weak margins and therefore decreased production levels.

Gas Services
The Company’s Gas Services business markets natural gas to optimize Enbridge’s commitments on the Alliance and Vector Pipelines. It also has a growing business of providing fee for service arrangements for third parties, leveraging its marketing expertise. Capacity commitments as of December 31, 2006 were 31.6 mmcf/d on the Alliance Pipeline (2.4% of total capacity) and 159.2 mmcf/d on Vector Pipeline (15.9% of total capacity). In December 2005, capacity commitments on Vector Pipeline of 82.5 mmcf/d, previously held by EGD were assumed by the Gas Services business.

Earnings from Gas Services are dependent upon the basis (location) differentials between Alberta and Chicago, for Alliance Pipeline, and between Chicago and Dawn, for Vector Pipeline. To the extent that the cost of transportation on these two pipelines exceeds the gas commodity basis differential, earnings will be negatively affected.

Other
Other earnings were $5.4 million in 2006 compared with a loss of $2.9 million in 2005. The 2006 results included an increased contribution from Tidal Energy, which resulted from the expansion of the business into the U.S. at the end of 2005 and increased earnings from its physical storage program.

In 2005, Other included higher costs, compared with 2004, related to the development of the Rabaska LNG facility.

Tidal Energy
Tidal Energy (Tidal) provides crude oil and natural gas liquids marketing services for the Company and its customers in a full range of condensate and crude oil types including light sweet, light and medium sours and several heavy grades. Tidal transacts at many of the major North American market hubs and provides its customers with a variety of programs including flexible pricing arrangements, hedging programs, product exchanges, physical storage programs and total supply management, through the analysis and implementation of different transportation options, reduced quality differentials and tariff structures, and utilizing Risk Management Pricing options. Tidal’s business involves buying, selling and storing large quantities of crude oil. Tidal is primarily a physical barrel marketing company and in the course of its market activities, physical receipt or delivery shortfalls can create modest commodity exposures. Any open positions created from this physical business are tightly monitored by, and must comply with, the Company’s formal risk management policies. Earnings from Tidal are included in Other.

AltaGas
The Company sold its investment in AltaGas in the third quarter of 2004 for an after-tax gain of $97.8 million.

Strategy
Other Natural Gas Distribution Strategies
Enbridge intends to pursue natural gas business development opportunities complementary to the existing gas distribution and services businesses through:

	developing LNG regasification projects and related pipeline infrastructure,
	pursuing marketing and storage opportunities that optimize existing assets,
	continuing to develop and grow the wind power platform in a measured fashion,
	pursuing marketing and storage opportunities that optimize existing assets, and
	exploring gas-fired generation opportunities that are underpinned by long-term contracts and improve the utilization of existing assets. The approach is to slowly build this business and utilize partners to share development risks.

Further to this strategy, Enbridge is developing a number of projects, which are described below.

Rabaska LNG Facility
Enbridge, Gaz Metro and Gaz de France are continuing development of the previously announced Rabaska LNG terminal to be located on the St. Lawrence River in Levis, Quebec. The Levis municipal council is fully supportive of the project and a fiscal agreement has been executed. Options for all required land have been secured. Environmental and marine applications have been filed and are progressing. It is expected that all required permits would be obtained by early summer 2007. Discussions are in progress with potential LNG suppliers regarding long-term terminal use arrangements. The project is expected to cost approximately $840 million in total.

Ontario Wind Project
Enbridge is developing approximately 182 megawatts of wind power in the Municipality of Kincardine on the eastern shore of Lake Huron in Ontario. Construction will commence when final environmental and zoning approvals are obtained. The project is waiting for its Environmental Screening Report to be passed by the Ontario Ministry of Environment and its zoning laws to be approved by the Ontario Municipal Board. Total capital expenditures are expected to be approximately $425 million. Enbridge has entered into a 20-year electricity purchase agreement with the Ontario Power Authority for all the power produced by the project. The Company expects the Ontario Wind Project to be in service in late 2008.

Capital Expenditures
Capital expenditures in other Gas Distribution and Services businesses, including the Ontario Wind Project, described above, are expected to be approximately $225 million in 2007.