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 CONDITIONS

We have taken several tangible steps to enhance our liquidity position since the end of 2008. First, we continue to limit our capital expenditure activities to those projects strategic to us. We have also enhanced liquidity in the form of our $350 million 364-day Credit Facilities, as discussed below. Most significantly, we recently announced a joint funding arrangement for our Alberta Clipper expansion project, referred to as the Alberta Clipper Project, through which our general partner and other affiliates of ours and Enbridge Inc., or Enbridge, participate jointly in financing the United States portion of the construction project. Following our announcement of the Alberta Clipper joint funding arrangement, both Standard & Poor's Ratings Services and Moody's Investors Service revised their ratings outlook on our senior unsecured debt to stable from negative. Standard & Poor's also raised our short-term rating to A-2 from A-3, which allows us to once again access the commercial paper market. Lastly, in September 2009, in an effort to further satisfy our financing needs, we committed to sell certain of our non-core natural gas pipeline assets located predominantly outside of Texas (see below, Results of Operations, Natural Gas-Other Matters).

The steps we have taken as described above are intended to maintain sufficient liquidity to fund our remaining growth programs and sustain the present distribution rate to our unitholders, while preserving our credit rating. Maintaining adequate liquidity may also involve the issuance of debt and equity and could involve the additional sale of additional non-core assets, further 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 and nine month periods ended September 30, 2009 and 2008. We have removed from "Income from continuing operations" for each of the periods presented the amounts comprising the operating results of certain non-core natural gas pipeline assets that we committed to sell, which amounts are presented in "Income (loss) from discontinued operations."

                                                       For the three               For the nine
                                                       months ended                months ended
                                                       September 30,               September 30,
                                                    2009          2008          2009          2008
                                                               (unaudited; in millions)
Operating Income
Liquids                                            $ 132.7       $  95.5       $ 339.7       $ 246.8
Natural Gas                                           47.0          64.2         113.1         168.3
Marketing                                              9.2          10.9          37.5          (6.5 )
Corporate, operating and administrative               (0.9 )        (1.6 )        (3.0 )        (4.7 )

Total Operating Income                               188.0         169.0         487.3         403.9
Interest expense                                      60.7          50.7         169.9         129.6
Other income                                           2.8           0.2           2.5           1.5
Income tax expense                                     2.7           1.9           6.8           5.0

Income from continuing operations                    127.4         116.6         313.1         270.8
Income (loss) from discontinued operations           (67.9 )         2.8         (67.5 )        10.5

Net income                                            59.5         119.4         245.6         281.3
Less: Net income attributable to noncontrolling
interest                                               2.3             -           2.3             -

Net income attributable to general and limited
partner ownership interests in Enbridge Energy
Partners, L.P.                                     $  57.2       $ 119.4       $ 243.3       $ 281.3

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, NGL and crude oil prices. Some of these derivative financial instruments do not qualify for hedge accounting under the provisions of authoritative accounting guidance, 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

The operating income of our Liquids segment for the three and nine month periods ended September 30, 2009, as compared with the same periods in 2008, was affected by the following:

• Transportation rate increases that went into effect in January, April and July 2009, which include increases in our tolls associated with the annual index rate ceiling adjustments, additional facilities added and a true-up of prior year transportation rate surcharges;

• Completion and start-up of the second stage of our Southern Access expansion project, referred to as the Southern Access Project, and the Phase V expansion of our North Dakota system;

• Higher delivered volumes on our Lakehead system;

• Revenue recognized in the third quarter of 2009 resulting from our application of regulatory accounting to our Southern Access Project and Alberta Clipper Project; and

The above increases to operating income were partially offset by:

• Lower prices associated with the allowance oil we receive; and

• Increased operating costs and depreciation associated with the additional assets we have placed into service.

Natural Gas

In September 2009, we committed to sell certain of our non-core natural gas pipeline assets located predominantly outside of Texas. We have presented in "Income from discontinued operations" the income and loss we derived from these assets for the three and nine month periods ended September 30, 2009 and 2008. We recorded an impairment charge of $66.1 million in the three and nine month periods ended September 30, 2009 to reduce the carrying amount of the natural gas pipeline assets we classified as held for sale to our estimate of the fair value of these assets.

The following factors affected the operating income of our Natural Gas business for the three month period ended September 30, 2009 compared to the same period of 2008:

• A $36.9 million decrease resulting from $0.3 million of unrealized, non-cash, mark-to-market losses from derivative instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with gains of $36.6 million for the same period of 2008;

• An approximate $7 million reduction in revaluation losses with respect to our in-kind natural gas imbalances due to less volatile commodities markets during the three months of 2009 when compared to same period in 2008;

• Decline in transportation volumes associated with lower natural gas production in the areas we serve;

• The operational disruptions related to hurricanes Gustav and Ike as well as measurement losses that existed in 2008 were not present during the same periods of 2009; and

• Overall improvement in operating and administrative costs as a result of our cost reduction measures, partially offset by increased depreciation associated with our completed expansion projects.

For the nine month period ended September 30, 2009, in addition to the factors discussed above, we had $13.3 million of unrealized, non-cash, mark-to-market losses associated with derivative financial instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance compared with $41.4 million of gains we experienced in the same period of 2008.

Marketing

The operating results of our Marketing segment for the three month period ended September 30, 2009 compared to the same period in 2008 were affected by the following:

• A reduction in operating revenues and additional margin from the sale of natural gas to our customers as a result of lower natural gas prices;

• $2.0 million decline in unrealized, non-cash, mark-to-market net gains of $9.0 million in 2009 from $11.0 million in the same period of 2008 associated with derivative financial instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance;

• Continued narrowing of natural gas transportation differentials between market centers, which benefited our hedged transportation positions; and

• Revaluation losses with respect to our in-kind natural gas imbalances of $5.9 million in 2008 that were not present during the same period in 2009.

The operating results of our Marketing segment for the nine month period ended September 30, 2009 were positively affected by $19.6 million of unrealized, non-cash, mark-to-market gains associated with derivative financial instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance. The gains for the nine month period ended September 30, 2009 resulted primarily from our hedged transportation positions which benefitted from the narrowing of the differences between the purchase and sales prices of natural gas. Conversely, the operating results for the nine month period ended September 30, 2008 were negatively impacted by $23.9 million of unrealized, non-cash, mark-to-market losses associated with derivative financial instruments. The non-cash, mark-to-market losses resulted from increases in the forward and daily market prices of natural gas from December 31, 2007 to September 30, 2008.

Derivative Transactions and Hedging Activities

We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in interest rates and commodity prices and minimize variability in our cash flows. Based on our risk management policies, all of our derivative financial 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. We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. 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.

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" or "Interest expense" in our consolidated statements of income and disclosed as a reconciling item on our consolidated statements of cash flows:

                                        For the three months ended                   For the nine months ended
                                               September 30,                               September 30,
                                       2009                     2008               2009                    2008
                                                               (unaudited; in millions)
Natural Gas segment
Hedge ineffectiveness             $         (0.1 )         $          0.1      $        (0.7 )         $        (1.1 )
Non-qualified hedges                        (0.2 )                   36.5              (12.6 )                  42.5
Marketing
Non-qualified hedges                         9.0                     11.0               19.6                   (23.9 )

Commodity derivative fair
value gains                                  8.7                     47.6                6.3                    17.5
Corporate
Non-qualified interest rate
hedges                                      (1.4 )                      -                1.0                       -

Derivative fair value gains       $          7.3           $         47.6      $         7.3           $        17.5

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            For the nine months ended
                                              September 30,                         September 30,
                                         2009               2008               2009               2008
                                                            (unaudited; in millions)
Operating Results
Operating revenues                   $       262.1      $       209.2      $       709.9      $       555.2

Operating and administrative                  61.2               52.0              174.8              130.8
Power                                         33.7               35.0               96.9              104.6
Depreciation and amortization                 34.5               26.7               98.5               73.0

Operating expenses                           129.4              113.7              370.2              308.4

Operating Income                     $       132.7      $        95.5      $       339.7      $       246.8


Operating Statistics
Lakehead system:
United States(1)                             1,351              1,233              1,296              1,242
Province of Ontario(1)                         350                331                346                344

Total Lakehead system
deliveries(1)                                1,701              1,564              1,642              1,586

Barrel miles (billions)                        108                105                316                317

Average haul (miles)                           688                730                706                729

Mid-Continent system
deliveries(1)                                  241                227                239                238

North Dakota system:
Trunkline                                      107                101                108                103
Gathering                                        6                  6                  6                  6

Total North Dakota system
deliveries(1)                                  113                107                114                109

Total Liquids Segment Delivery
Volumes(1)                                   2,055              1,898              1,995              1,933

(1) Average barrels per day, or Bpd in thousands.

Three months ended September 30, 2009 compared with three months ended September 30, 2008

Our Liquids segment accounted for $132.7 million of operating income during the three months ended September 30, 2009, an increase of $37.2 million from the $95.5 million generated during the same period in 2008. The favorable results are primarily attributable to transportation rate increases that went into effect during 2009, increased volumes on our Lakehead system, partially offset by higher operating and administrative costs, and depreciation.

Operating revenue for the three months ended September 30, 2009 increased by $52.9 million to $262.1 million from $209.2 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;

• Higher delivered volumes on our Lakehead system;

• Additional revenue recognized in the third quarter of 2009 resulting from our application of the provisions of regulatory accounting; and

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

These increases in operating revenue were partially offset by lower average crude oil 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 $33.8 million of additional operating revenue. The rate increases included the following:

• 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;

• Effective April 1, 2009, we increased the rates for transportation on our Lakehead system in connection with the completion of Stage 2 of our Southern Access Project. We also increased the transportation rates on our Lakehead system for additional facilities we added for which we receive a cost-of-service return and a true-up for costs associated with our Southern Access Stage 1 project; and

• Effective July 1, 2009, we increased the average transportation rates on all three of our Liquids systems in connection with the annual index rate ceiling adjustment.

Average delivery volumes on our Lakehead system increased approximately 8.8 percent, to 1.701 million Bpd for the three months ended September 30, 2009 from 1.564 million Bpd during the same period in 2008, contributing $14.2 million to operating revenue. The increase in average deliveries on our Lakehead system is primarily due to increases of crude oil supplies from upstream production facilities associated with the ongoing development of the Alberta Oil Sands.

For the three months ended September 30, 2009, we recognized $7.4 million of revenue and a corresponding regulatory receivable for amounts we expect to recover in the future due to fewer volumes being transported on our system than anticipated when our current rates were established under the cost-of-service recovery model. These revenues were earned during 2009, but will not be realized as cash until 2010 when we update our transportation rates to account for the lower actual delivered volume than estimated. In April 2009, we applied the provisions of regulatory accounting to the operations of our Southern Access Project when the facilities rate surcharge associated with the project was both approved by the Federal Energy Regulatory Commission, referred to as the FERC, and uncontested by any of our customers. The rates for the Southern Access Project are based on a cost-of-service recovery model that follows the FERC's authoritative guidance and is subject to the annual filing requirements with the FERC. The rates we are allowed to charge shippers associated with our Southern Access Project include an allowance that provides a rate of return to our partners.

Also contributing to the increase in revenues for the three months ended September 30, 2009, was an approximately $3.7 million increase in storage fees generated by our Mid-Continent system due to wider storage spreads in the market coupled with increased spot storage fee revenue.

Our transportation tariffs allow 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 September 30, 2009 are substantially lower than the average prices for the same period of 2008. For example, the average daily price of West Texas Intermediate crude oil has decreased approximately 42 percent for the three months ended September 30, 2009 as compared with the same period in 2008. As a result of the decrease in crude oil prices, we have experienced an approximate $6.8 million decrease in allowance oil revenues.

Operating and administrative expenses for the Liquids segment increased $9.2 million for the three months ended September 30, 2009, compared with the same period in 2008. The increase in these costs is primarily attributable to the following:

• Higher operating costs associated with our lease of Line 13 from an affiliate of our general partner which contributed $5.4 million to our costs and which we are recovering through a tolling surcharge on our Lakehead system with the net effect on our cash flow expected to approximate zero;

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

• Slightly increased operating costs associated with pigging batches at our Flanagan terminal.

These increases in operating and administrative expenses were slightly offset by decreased property taxes. We revised our estimate for 2009 property taxes in the third quarter of 2009, resulting in a lower property tax expense as compared with the same period of 2008, which did not include a similar revision.

Power costs decreased $1.3 million in the three months ended September 30, 2009, compared with the same period in 2008. The decline in power costs is primarily associated with the additional capacity provided by our Southern Access Project that has enabled us to more efficiently utilize our pipelines to transport crude oil.

The increase in depreciation expense of $7.8 million is attributable to the additional assets we have placed in service during the last quarter of 2008 and the first nine months of 2009, primarily the second stage of the Southern Access Project assets which we placed in service on April 1, 2009.

Nine months ended September 30, 2009 compared with nine months ended September 30, 2008

Our Liquids segment accounted for $339.7 million of operating income during the nine months ended September 30, 2009, representing a $92.9 million increase over the $246.8 million for the same period in 2008. In addition to the factors explaining the changes noted in our three month analysis, operating income for the nine month period ended September 30, 2009 as compared with the nine month period ended September 30, 2008 was affected by approximately $13.5 million of previously unbilled operating revenues on our Lakehead system that resulted from incorrectly invoicing shippers at one of our delivery points from October 2005 through December 2008 that we recorded in March 2009.

We also experienced less favorable oil measurement adjustments which occur as part of the normal operations associated with our Liquids systems and contributed an approximately $12.8 million increase in our operating expenses for the nine months ended September 30, 2009, as compared with the same period in 2008. Our oil measurement expense level, while less favorable than 2008, is within acceptable industry tolerances. 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.

Other Matters

Line 13 Exchange and Lease

In connection with the development of a diluent pipeline being constructed by Enbridge Pipelines (Southern Lights), L.L.C., or Southern Lights, a wholly-owned subsidiary of our general partner, we completed the transfer of a 156-mile section of pipeline, which we refer to as Line 13, from our Lakehead system to Southern Lights, in exchange for a newly constructed pipeline for transporting light sour crude oil. 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 from Southern Lights 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 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 are being recovered through a tolling surcharge on our Lakehead system and the net effect on our cash flow over the life of the transaction is expected to approximate zero. The exchange resulted in a $168.8 million increase in "Property, plant and equipment" and the capital account of our general partner included in "Partners' capital" on our September 30, 2009 consolidated

statement of financial position, representing the $173.8 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. Subsequent to the initial exchange, an additional . . .