The following discussion and analysis of our financial condition and results of operations should be read together with our consolidated financial statements and the accompanying notes included in "Item 1. Financial Statements" of this report.

Additionally, this quarterly report on Form 10-Q should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2008.

IMPACT OF CURRENT ECONOMIC CRISIS

The weakened world economy that existed in the last half of 2008 has continued through the first three months of 2009. Liquidity constraints continue to exist within the capital markets of the United States ("U.S.") and around the world. Our ability to raise debt and equity at prices that are similar to offerings in recent years continues to be limited and is expected to remain so as long as the capital markets remain constrained.

We intend to move forward with our planned internal growth projects, although our capital spending, particularly on the natural gas side of our business, will be tempered to reduce our capital raising requirements. In the near-term, we will focus on maintaining sufficient liquidity to fund our growth programs, see "Liquidity and Capital Resources." Maintaining adequate liquidity may involve the issuance of debt and equity at less attractive terms than our most recent offerings and could involve the sale of non-core assets, asset partnership or joint venture arrangements or other strategies to limit the amount of external funding required for our growth projects.

RESULTS OF OPERATIONS-OVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following activities:

• Interstate pipeline transportation and storage of crude oil and liquid petroleum;

• Gathering, treating, processing and transportation of natural gas and natural gas liquids, or NGLs, through pipelines and related facilities; and

• Supply, transportation and sales services, including purchasing and selling natural gas and NGLs.

We conduct our business through three business segments: Liquids, Natural Gas and Marketing. These segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

The following table reflects our operating income by business segment and corporate charges for the three month periods ended March 31, 2009 and 2008.

                                             For the three months ended March 31,
                                                2009                      2008
                                                   (unaudited; in millions)
Operating Income
Liquids                                   $           102.2         $            61.6
Natural Gas                                            17.2                      72.2
Marketing                                               3.9                       0.5
Corporate, operating and administrative                (0.9 )                    (2.0 )

Total Operating Income                                122.4                     132.3
Interest expense                                       51.3                      27.6
Other expense                                           0.5                       0.3
Income tax expense                                      2.0                       1.3

Net Income                                $            68.6         $           103.1

Contractual arrangements in our Natural Gas and Marketing segments expose us to market risk associated with changes in commodity prices where we receive natural gas or NGLs in return for the services we provide or where we purchase natural gas or NGLs. Our unhedged commodity position is fully exposed to fluctuations in commodity prices. These fluctuations can be very significant as evidenced by commodity prices during 2008. We employ derivative financial instruments to hedge a portion of our commodity position and to reduce our exposure to fluctuations in natural gas and NGL prices. Some of these derivative financial instruments do not qualify for hedge accounting under the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"), which can create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

Summary Analysis of Operating Results

Liquids

Operating income from our Liquids segment increased by $40.6 million to $102.2 million for the three months ended March 31, 2009, from the $61.6 million generated during the same period of 2008. The operating income of our Liquids segment was affected by the following:

• Tariff increases that went into effect in April and July 2008 and January 2009, which include increases associated with the first stage of our Southern Access Expansion and the Phase V expansion of our North Dakota system; and

• Additional revenue we recorded in the first quarter of 2009 resulting from our joint tolling arrangement with Mustang Pipe Line, LLC ("Mustang").

The above increases to operating income were partially offset by:

• Reduced delivery volumes on our Lakehead system resulting from the line-filling of the first stage of our Southern Access Expansion in March 2009;

• Lower prices associated with the allowance oil we receive coupled with unfavorable oil measurement adjustments; and

• Increased workforce-related and other operating costs.

Natural Gas

Operating income from our Natural Gas segment decreased by $55.0 million to $17.2 million for the three months ended March 31, 2009, from the $72.2 million for the same period of 2008. The following factors affected the operating income of our Natural Gas business:

• $10.0 million of unrealized, non-cash mark-to-market losses from derivative instruments that do not qualify for hedge accounting treatment under SFAS No. 133, as compared with gains of $26.8 million for the same period of 2008;

• Lower margins resulting from the overall deterioration of natural gas and NGL prices as compared with the first three months of 2008;

• Volume growth associated with the completion of our East Texas natural gas system expansion and extension, referred to as the Clarity Project; and

• Increased workforce-related costs coupled with variable operating and administrative cost increases associated with our system growth.

Marketing

Operating income from our Marketing segment increased by $3.4 million to $3.9 million for the three months ended March 31, 2009 compared to $0.5 million in the same period in 2008. The operating results of our Marketing segment for the three months ended March 31, 2009 were positively affected by $6.0 million fewer

unrealized, non-cash, mark-to-market losses associated with derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133 as compared with the same period in 2008. Partially offsetting the lower unrealized non-cash, mark-to-market losses were $2.9 million of non-cash charges for the three months ended March 31, 2009 we recorded to reduce the cost basis of our natural gas inventory to fair market value. The non-cash, mark-to-market losses and revaluation charges during the three months ended March 31, 2009 resulted from wider transportation differentials and the declines in natural gas prices, respectively.

Derivative Transactions and Hedging Activities

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of SFAS No. 133 and the guidance set forth in SFAS No. 157, Fair Value Measurement ("SFAS No. 157"). For those derivative instruments that do not qualify for hedge accounting, we record all changes in fair market value through our consolidated statements of income each period. Based on our risk management policies, all of our derivative instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.

In our natural gas business, the forward prices for natural gas at December 31, 2008 were greater than these prices at March 31, 2009, producing unrealized, non-cash mark-to-market net losses of $10.0 million from the derivative instruments we use to fix the price of the natural gas we purchase for processing. These net losses were partially offset by unrealized non-cash mark-to-market net gains resulting from modestly lower forward NGL prices at March 31, 2009 as compared with the prices at December 31, 2008, associated with the derivatives we use to hedge the sales prices of a portion of the NGLs we derive from processing natural gas. Comparatively, at December 31, 2007 the forward prices for natural gas were lower than the prices at March 31, 2008, which produced $26.8 million of unrealized, non-cash mark-to-market net gains on the derivative instruments used to fix the price of the natural gas we purchase for processing. These net gains were partially offset by unrealized non-cash mark-to-market net losses resulting from modestly higher forward and daily NGL prices at March 31, 2008 as compared with the prices at December 31, 2007, associated with the derivatives we use to hedge the sales prices of a portion of the NGLs we derive from processing natural gas.

In our marketing business, the lower forward prices for natural gas at March 31, 2009 in relation to the prices at December 31, 2008, produced unrealized non-cash mark-to-market net losses of $6.9 million in our portfolio of derivative instruments we use to fix the price of natural gas we purchase for storage activities. Partially offsetting net losses associated with the derivative instruments we use for our storage activities, were gains resulting from narrowing basis differentials (the relative difference in the price we pay to purchase natural gas at one location and the price we receive from the sale of natural gas to our customers at another location), on derivative instruments we use to hedge our transportation activities. For the same period of 2008, the forward prices of natural gas were higher at March 31, 2008 than the prices at December 31, 2007, producing $12.9 million of losses on our derivative instruments.

We intend to continue using derivative instruments in our Natural Gas and Marketing businesses to hedge our portfolio of natural gas and NGLs because of the benefit we derive from reducing the volatility in our cash flows. Our continued use of derivative instruments is likely to result in additional unrealized, non-cash gains and losses in the future. We expect the net mark-to-market losses to be offset when the related physical transactions are settled.

The following table presents the unrealized gains and losses associated with changes in the fair value of our derivative instruments, which are recorded as an element of "Cost of natural gas" in our consolidated statements of income and disclosed as a reconciling item on our consolidated statements of cash flows:

                                                     For the three months ended March 31,
                                                     2009                            2008
                                                           (unaudited; in millions)
Natural Gas segment
Hedge ineffectiveness                          $            (0.2 )             $            (1.8 )
Non-qualified hedges                                        (9.8 )                          28.6
Marketing
Non-qualified hedges                                        (6.9 )                         (12.9 )

Commodity derivative fair value
gains (losses)                                             (16.9 )                          13.9
Corporate
Non-qualified interest rate hedges                             -                            (0.2 )

Derivative fair value gains (losses)           $           (16.9 )             $            13.7

RESULTS OF OPERATIONS-BY SEGMENT

Liquids

The following tables set forth the operating results and statistics of our
Liquids segment assets for the periods presented:



                                              For the three months ended March 31,
                                                   2009                   2008
                                                    (unaudited; in millions)
Operating Results
Operating revenues                          $            219.4     $            157.0

Operating and administrative                              54.4                   37.5
Power                                                     33.4                   38.3
Depreciation and amortization                             29.4                   19.6

Operating expenses                                       117.2                   95.4

Operating Income                            $            102.2     $             61.6

Operating Statistics
Lakehead system:
United States(1)                                         1,265                  1,257
Province of Ontario(1)                                     354                    380

Total Lakehead system deliveries(1)                      1,619                  1,637

Barrel miles (billions)                                    105                    109

Average haul (miles)                                       720                    729

Mid-Continent system deliveries(1)                         239                    251

North Dakota system:
Trunkline                                                  108                    103
Gathering                                                    6                      5

Total North Dakota system deliveries(1)                    114                    108

Total Liquids Segment Delivery Volumes(1)                1,972                  1,996

(1) Average barrels per day ("Bpd") in thousands.

Three months ended March 31, 2009 compared with three months ended March 31, 2008

Our Liquids segment accounted for $102.2 million of operating income during the three months ended March 31, 2009, an increase of $40.6 million from the $61.6 million generated during the same period in 2008. The favorable results are primarily attributable to tariff increases that went into effect during 2008 and 2009 and additional revenue that was recognized in the first quarter of 2009 as a result of a joint tariff invoicing error that occurred in prior periods, partially offset by higher operating and administrative costs, and depreciation.

Operating revenue for the three months ended March 31, 2009 increased by $62.4 million to $219.4 million from $157 million for the same period in 2008. The increase in operating revenue is due to the following:

• Increased average rates for transportation on all of our major systems as noted below;

• Additional revenue we recognized in the first quarter of 2009 resulting from our joint tolling arrangement with Mustang; and

• Additional contract storage fees revenue generated by our Mid-Continent storage terminal system.

These increases in operating revenue were partially offset by the following:

• Lower delivered volumes on our Lakehead system resulting from the line-filling of the first stage of our Southern Access Expansion; and

• Lower prices associated with the allowance oil we receive in connection with our transportation services.

Increases in average transportation rates on all three Liquids systems contributed approximately $55.5 million of additional operating revenue. We filed and implemented new tariff rates in 2008 on our Lakehead system, effective April 1, 2008, to reflect the completion of four projects: (1) the Southern Access mainline expansion, (2) two Superior terminal tank projects, (3) two Griffith terminal tank projects and (4) the Clearbrook Manifold project. Effective July 1, 2008, we increased the average transportation rates on all three of our Liquids systems in connection with the annual index rate ceiling adjustment. Additionally, effective January 1, 2009, we increased the rates for transportation on our North Dakota system to include an updated calculation of the two surcharges related to the Phase V Expansion program. We expect our transportation revenues to grow over the rest of 2009 due to the Southern Access Surcharge that became effective April 1, 2009 which include rates related to our recently completed Stage 2 Southern Access Expansion. Additional discussion of these tariffs is provided below under the section labeled Regulatory Matters-FERC Transportation Tariffs-Liquids.

During the three months ended March 31, 2009, we recorded approximately $13.8 million of previously unbilled operating revenues associated with our Lakehead system that relate to incorrectly invoicing shippers from October 2005 through December 2008. Enbridge Energy, Limited Partnership (the "Enbridge Partnership"), our wholly-owned subsidiary, is party to a joint tariff agreement with Mustang, a business partially-owned by Enbridge Inc. ("Enbridge") (30%) and a major integrated oil company (70%.) Mustang receives crude oil from the Enbridge Partnership system in the Chicago, Illinois market area. Crude oil delivered to Mustang is then transported on their pipeline system to markets south of Chicago. The joint tariff agreement in place with Mustang allows for shippers on our Lakehead system to reach markets downstream of Chicago by providing committed shippers with a discounted transportation rate for their commitments to transport crude oil exiting our Lakehead system in the Chicago region through the Mustang pipeline. Since October 2005, a shipper on our Lakehead system, which was not a committed shipper, was incorrectly invoiced at the discounted transportation rate. Additionally, we continued to invoice two shippers whose commitments expired in September 2008 at discounted transportation rates rather than the undiscounted non-committed shipper rates. As a result of invoicing these shippers at the discounted rate rather than the undiscounted rate, we did not record approximately $13.8 million of operating revenues on our Lakehead system from October 2005 through December 2008. The unrecorded revenues were not material to prior financial statement periods and we have included the entire $13.8 million in our consolidated statement of income for the three months ended March 31, 2009.

Also contributing to the increase in revenues for the three months ended March 31, 2009, was an approximately $3.2 million increase in contract storage and spot storage fees generated by our Mid-Continent system derived primarily from increased spot storage deals.

Average delivery volumes on our Lakehead system decreased approximately 1.1 percent, to 1.619 million Bpd during the three months ended March 31, 2009 from 1.637 million Bpd during the same period in 2008, contributing a decrease of $2.5 million to operating revenue. The decrease in average deliveries on our Lakehead system is primarily the result of the line-filling of the first stage of our Southern Access expansion that occurred in March 2009. Filling the pipeline reduced deliveries for the three months ended March 31, 2009 by approximately 27,000 Bpd, since the crude oil shipped by customers on our Southern Access pipeline is not delivered. We expect volumes to increase in the second half of the year after we have completed line-filling the Southern Access pipeline. Further compounding the reduced delivery volumes was a decrease in crude oil supplies from upstream production facilities of the oil sands in Alberta, Canada, ("Alberta Oil Sands") due to delays in upgrader projects and turnaround maintenance.

Our transportation tariff allows our pipelines to deduct an allowance from our customers for the transportation of their crude oil. We recognize revenue for this allowance at the prevailing market price for crude oil. The average prices of crude oil during the three months ended March 31, 2009 are substantially lower than the average prices for the same period of 2008. For example, the average price of West Texas Intermediate crude oil has decreased approximately 56 percent for the three months ended March 31, 2009 as compared with the same period in 2008. As a result of the decrease in crude oil prices, we experienced an approximate $7.6 million decrease in allowance oil revenues.

Operating and administrative expenses for the Liquids segment increased $16.9 million for the three months ended March 31, 2009, compared with the same period in 2008. The increase in these costs is primarily attributable to the following:

• Increased workforce related costs associated with the operational, administrative, regulatory, and compliance support necessary for our growing systems;

• Unfavorable oil measurement adjustments as described below, primarily attributable to physical and revaluation adjustments;

• Favorable settlements of property tax assessments that were realized during the three months ended March 31, 2008, which were not present for the same period in 2009; and

• Higher operating costs mainly attributable to the Line 13 lease for $2.3 million for the quarter as discussed in Item 1. Financial Statements-Note 8-Related Party Transactions-Line 13 Exchange and Lease, which will be recovered through a tolling surcharge on our Lakehead system with the net effect on our cash flow expected to approximate zero beginning April 1, 2009.

Oil measurement adjustments occur as part of the normal operations associated with our Liquids systems. The three types of oil measurement adjustments that normally occur on our systems include:

• Physical, which results from evaporation, shrinkage, differences in measurement between receipt and delivery locations and other operational incidents;

• Degradation, which results from mixing at the interface between higher quality light crude oil and lower quality heavy crude oil; and

• Revaluation, which is a function of crude oil prices, the level of our carriers' inventory and the inventory positions of customers.

Power costs decreased $4.9 million in the three months ended March 31, 2009, compared with the same period in 2008, predominantly due to the lower delivery volumes transported on our systems.

The increase in depreciation expense of $9.8 million is attributable to the additional assets we have placed in service during the last three quarters of 2008, primarily the Southern Access Expansion stage one assets that we placed in service during the second quarter of 2008.

Other Matters

In connection with the development of a diluent pipeline being constructed by Enbridge Pipelines (Southern Lights), L.L.C. ("Southern Lights"), a wholly-owned subsidiary of our general partner, we completed the transfer of a 156-mile section of pipeline from our Lakehead system ("Line 13") to Southern Lights, in exchange for a newly constructed light sour pipeline. In connection with the exchange, at the request of shippers and to ensure adequate southbound pipeline capacity prior to the completion of the Alberta Clipper project, we agreed to lease Line 13 back for monthly payments of $1.8 million. The transfer and lease became effective February 20, 2009, which was the in-service date for the light sour pipeline. The lease of Line 13 will be effective until the earliest of
(i) July 1, 2010, (ii) upon the transfer of the Canadian portion of Line 13 from Enbridge Pipelines Inc. ("Enbridge Pipelines"), a subsidiary of Enbridge, to Enbridge Southern Lights LP, a wholly-owned subsidiary of Enbridge Pipelines, or
(iii) early termination of the lease. We are able to terminate the lease at any time during the term by providing Southern Lights with written notice, at which time we would only be required to return Line 13 to Southern Lights. The costs associated with the lease will be recovered through a tolling surcharge on our Lakehead system and the net effect on our cash flow is expected to approximate zero. The exchange resulted in a $160.7 million increase in "Property, plant and equipment" and the capital account of our general partner included in "Partners' capital" on our March 31, 2009 consolidated statement of financial position for the $165.7 million cost of the light sour pipeline that was in excess of the $5.0 million net book value of the Line 13 assets we exchanged. The light sour line is newer and has a slightly higher capacity than the Line 13 pipeline, which will allow us to transport additional volumes of light sour crude oil on our Lakehead system with less integrity and maintenance costs, although depreciation expense is anticipated to increase in future periods due to the higher book value associated with these assets.

Future Prospects Update for Liquids

We and Enbridge are actively working with our customers to develop transportation options that will allow Canadian crude oil greater access to markets throughout the U.S. The following discussion provides an update to the status of projects that we and Enbridge are developing and should be read in conjunction with the information included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2008.

Partnership Projects

Southern Access

We completed the second and final stage of our Southern Access expansion project and placed it into service on April 1, 2009. The related tolling surcharge has been adjusted to include costs of this phase of the expansion and became effective April 1, 2009. We will begin to realize revenues in connection with this increased surcharge as crude oil is delivered from our pipeline, generally the month following the effective date of the tariff. This stage provides additional upstream pumping capacity and a new pipeline from Delavan, Wisconsin to Flanagan, Illinois. Completion of the total Southern Access expansion project created a 454-mile pipeline with approximately 400,000 Bpd of incremental capacity on our Lakehead system, which can be further expanded to 1.2 million Bpd with expenditures for additional pumping equipment. The commercial structure for this expansion is a cost-of-service based surcharge that has been added to the existing transportation rates. We anticipate that earnings before interest, taxes, depreciation, and amortization ("EBITDA") associated with this project will be approximately $230 million to $250 million annually in the first full year that both stages of the Southern Access project are fully operational.

Alberta Clipper

The Alberta Clipper project involves construction of a new 36-inch diameter, 1,000 mile heavy crude oil pipeline from Hardisty, Alberta to Superior, Wisconsin, generally within or adjacent to our and Enbridge's existing rights-of-way. We will construct approximately 330 miles of the new pipeline from the International Border near Neche, North Dakota to Superior, a delivery . . .