The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes beginning in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

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 each of the years ended December 31, 2012, 2011 and 2010.

                                                                   December 31,
                                                      2012             2011             2010
                                                                   (in millions)
Operating Income (loss)
Liquids                                             $   706.8        $   816.2        $   (24.7 )
Natural Gas                                             200.1            183.6            152.4
Marketing                                               (11.4 )           (0.8 )            3.7
Corporate, operating and administrative                  (2.3 )           (2.2 )           (4.1 )

Total Operating Income                                  893.2            996.8            127.3
Interest expense                                        345.0            320.6            274.8
Other income                                             10.0              6.5             17.5
Income tax expense                                        8.1              5.5              7.9

Net income (loss)                                       550.1            677.2           (137.9 )
Less: Net income attributable to noncontrolling
interest                                                 57.0             53.2             60.6

Net income (loss) attributable to general and
limited partner ownership interests in Enbridge
Energy Partners, L.P.                               $   493.1        $   624.0        $  (198.5 )

Contractual arrangements in our Liquids, Natural Gas and Marketing segments expose us to market risks associated with changes in commodity prices where we receive crude oil, 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 significant if commodity prices experience significant volatility. We employ derivative financial instruments to hedge a portion of our commodity position and to reduce our exposure to fluctuations in crude oil, natural gas and NGL 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

Our Liquids segment includes the operations of our Lakehead, North Dakota and Mid-Continent systems. These systems largely consist of FERC-regulated interstate crude oil and liquid petroleum pipelines, gathering systems and storage facilities. The Lakehead system, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. Our Liquids systems generate revenues primarily from charging shippers a rate per barrel to gather, transport and store crude oil and liquid petroleum.

The operating income of our Liquids business for the year ended December 31, 2012 decreased $109.4 million, as compared with the same period in 2011, primarily due to the following:

• Increased average daily volumes resulting in $25.1 million additional operating revenue;

• Increased operating revenue of $17.0 million due to higher indexed tariff rates for our Lakehead, North Dakota and Ozark systems;

• Increased operating revenue of $14.9 million for fees collected from our Cushing storage terminal facility;

• Increased operating revenue of $11.8 million due to higher recovery of capital costs in our annual tolls related to the Line 6B Pipeline Integrity Plan;

• Increased environmental costs, net of insurance recoveries, of $21.6 million for the year ended December 31, 2012 when compared to the same period of 2011;

• Decreased unrealized, non-cash, mark-to-market net gains of $13.1 million for the year ended December 31, 2012, on derivative financial instruments that do not qualify for hedge accounting treatment;

• Increased "Operating and administrative" expenses of $79.4 million primarily due to:

- Increased workforce related costs and other allocated expenses of $28.2 million;

- Increased supporting costs of $16.0 million related to professional and regulatory expenses, maintenance, supplies and other outside services;

- Increased property tax expenses of $14.8 million; and

- Increased pipeline integrity costs of $11.2 million.

• Increased Oil measurement adjustments due to a $52.2 million settlement with a shipper on our Lakehead crude oil pipeline system in 2011 that did not occur in 2012;

• Increased power costs of $4.0 million primarily associated with the higher volumes of crude oil transported on our Lakehead system; and

• Increased depreciation expense of $12.9 million for the year ended December 31, 2012, directly attributable to additional assets placed into service since 2011.

Natural Gas

Our Natural Gas segment consists of natural gas gathering and transmission pipelines as well as natural gas treating and processing plants and related facilities. The revenues of our Natural Gas segment are associated with services we provide to gather and process natural gas and to transport natural gas on our pipelines. Generally, our revenues are in the form of fee for service arrangements and sales of natural gas and NGLs.

The operating income of our Natural Gas business for the year ended December 31, 2012 increased $16.5 million, as compared with the same period in 2011, primarily due to the following:

• Decreased gross margin due to the significant decline in natural gas and NGL prices for the year ended December 31, 2012 when compared to the same period in 2011;

• Increased operating revenue less the cost of natural gas derived from keep-whole processing earnings of $49.2 million;

• Increased operating income of approximately $33.0 million due to "accounting misstatements" and "accounting errors" for NGL product purchases and sales made by our trucking and NGL marketing subsidiary for the year ended December 31, 2010 that were recorded for the year ended December 31, 2011 with no such misstatements or errors recorded for the year ended December 31, 2012;

• Increased operating income of approximately $13.0 million due to unusually adverse weather conditions and plant downtime for the year ended December 31, 2011 that negatively impacted gross margin relative to typical weather related upsets experienced in 2012;

• Increased fee-based operating income of approximately $13.0 million on our East Texas, Anadarko, and Oklahoma systems due to higher fees resulting from lower field operating pressures, contract changes, and additional Haynesville volumes;

• Increased operating income of approximately $11.2 million from improved Anadarko NGL processing efficiencies and higher NGL content in the natural gas processing stream;

• Increased operating income of approximately $10.8 million from our condensate marketing business due to higher realized margins from facilities placed into service during 2012;

• Decreased operating income of $11.5 million in unrealized, non-cash, mark-to-market net gains from derivative instruments that do not qualify for hedge accounting treatment, as compared with the same period of 2011;

• Increased operating and administration costs of $67.2 million for the year ended December 31, 2012, as compared with the same period in 2011 primarily due to:

- Increased workforce related costs and other allocated expenses of $26.0 million primarily due to programs and initiatives focused on renewing our focus on safety, operations and systems integrity in addition to the completion of the Allison plant and other assets being placed into service during 2011;

- Increased supporting costs of $10.6 million related to maintenance, supplies and other outside services also associated with additional assets being placed into service during 2011;

- Increased current year costs of $7.5 million for investigation costs related to accounting misstatements at our trucking and NGL marketing subsidiary;

- Increased integrity costs of $7.2 million as part of the operational risk management plan to ensure our systems are safe and to maintain our existing pipelines;

- Increased current year costs of $4.3 million for the write down of surplus materials associated with the deferred portions of the Haynesville expansion within our East Texas system; and

• Decreased depreciation expense of $7.8 million, for the year ended December 31, 2012, primarily due to a revision in depreciation rates for the Anadarko, North Texas and East Texas systems in 2011.

Marketing

Our Marketing segment provides supply, transmission, storage and sales services to producers and wholesale customers on our natural gas gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Our Marketing activities are primarily undertaken to realize incremental revenue on gas purchased at the wellhead, increase pipeline utilization and provide other services that are valued by our customers.

The operating income of our Marketing business for the year ended December 31, 2012 decreased $10.6 million, as compared with the same period of 2011. Primarily contributing to the operating loss of our Marketing business were lower and relatively stable natural gas prices during the year ended December 31, 2012, when compared to the same period of 2011, which limited opportunities to benefit from price differentials between market centers.

Additionally, the operating results of our Marketing business for the year ended December 31, 2012 included unrealized, non-cash, mark-to-market, net losses of $3.1 million associated with derivative financial instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with $0.7 million of unrealized, non-cash, mark-to-market, net gains for the year ended December 31, 2011.

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 commodity prices and interest rates and to reduce 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 commodity prices or interest rates. We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income as follows:

• Liquids segment commodity-based derivatives-"Operating revenue" and "Power"

• Natural Gas and Marketing segments commodity-based derivatives-"Cost of natural gas"

• Corporate interest rate derivatives-"Interest expense"

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net unrealized gains and losses associated with the changes in fair value of our derivative financial instruments:

                                                                   December 31,
                                                        2012           2011           2010
                                                                  (in millions)
Liquids segment
Non-qualified hedges                                  $    1.3       $   14.4       $   (2.8 )
Natural Gas segment
Hedge ineffectiveness                                      3.1           (5.3 )          3.5
Non-qualified hedges                                       1.2           21.1            0.9
Marketing
Non-qualified hedges                                      (3.1 )          0.7           (6.7 )

Commodity derivative fair value net gains (losses)         2.5           30.9           (5.1 )
Corporate
Hedge ineffectiveness                                    (20.5 )         (0.3 )           -
Non-qualified interest rate hedges                        (0.5 )         (0.5 )         (1.0 )

Derivative fair value net gains (losses)              $  (18.5 )     $   30.1       $   (6.1 )

RESULTS OF OPERATIONS-BY SEGMENT

Liquids

Our Liquids segment includes the operations of our Lakehead, North Dakota and
Mid-Continent systems. We provide a detailed description of each of these
systems in Item 1. Business. The following tables set forth the operating
results and statistics of our Liquids segment for the periods presented:



                                                              December 31,
                                                   2012           2011           2010
                                                              (in millions)
 Operating Results
 Operating revenues                              $ 1,345.8      $ 1,285.4      $ 1,171.8

 Environmental costs, net of recoveries              (91.3 )       (112.9 )        600.8
 Oil measurement adjustments                         (11.5 )        (63.4 )          5.6
 Operating and administrative                        383.0          303.6          259.9
 Power                                               148.8          144.8          141.1
 Depreciation and amortization                       210.0          197.1          178.8
 Impairment charge                                      -              -            10.3

 Operating expenses                                  639.0          469.2        1,196.5

 Operating income (loss)                         $   706.8      $   816.2      $   (24.7 )

 Operating Statistics
 Lakehead system:
 United States(1)                                    1,405          1,327          1,302
 Province of Ontario(1)                                385            373            353

 Total Lakehead system delivery volumes(1)           1,790          1,700          1,655

 Barrel miles (billions)                               480            450            439

 Average haul (miles)                                  732            725            727

 Mid-Continent system delivery volumes(1)(2)           223            226            212

 North Dakota system:
 Trunkline                                             203            193            159
 Gathering                                               3              4              6

 Total North Dakota system delivery volumes(1)         206            197            165

 Total Liquids segment delivery volumes(1)           2,219          2,123          2,032

(1) Average barrels per day in thousands.

(2) Includes average system deliveries of 7,000 Bpd for the year ended 2010, from the West Tulsa crude oil pipeline which was removed from service in September 2010.

Year ended December 31, 2012 compared with year ended December 31, 2011

The operating revenue of our Liquids segment increased for the year ended December 31, 2012 when compared with the same period in 2011, partially due to higher average daily delivery volumes on our Lakehead and North Dakota systems when compared to the same period in 2011. The overall increase in average delivery volumes on our systems increased operating revenues by $25.1 million for our Liquids segment. The total average daily deliveries from our liquid systems increased over 4%, to 2.219 million barrels per day, or Bpd, for

the year ended December 31, 2012 from 2.123 million Bpd for the year ended 2011. The increase in average deliveries on our liquids systems was primarily derived from increases of crude oil supplies from conventional sources as well as strong refinery utilization in PADD II.

Our operating revenue was positively impacted by the filing of tariffs to increase the rates for our Lakehead, North Dakota and Ozark systems with Federal Energy Regulatory Commission, or FERC, that became effective July 1, 2012. These rate increases resulted from application of the index allowed by FERC. This change in index comprises approximately $17.0 million of the increase in operating revenue for the year ended December 31, 2012 when compared to the same period in 2011.

Our operating revenue increased by $14.9 million during the year ended December 31, 2012 due to the collection of fees from our Cushing storage terminal facilities, with the majority of these incremental revenues coming from storage facilities which were placed into service in 2012.

In addition, our operating revenues increased by $11.8 million due to higher recovery of capital costs we recovered through our annual tolls under our Facilities Surcharge Mechanism, or FSM, related to the Line 6B Pipeline Integrity Plan for the year ended December 31, 2012 compared to the same period in 2011.

The operating revenue of our Liquids business was negatively impacted for the year ended December 31, 2012 when compared with the same period in 2011 by a $13.1 million decrease in unrealized, non-cash, mark-to-market net gains for year ended December 31, 2012, related to derivative financial instruments as compared with the same period in 2011, due to changes in average forward prices of crude oil for the respective periods. We use forward contracts to hedge a portion of the crude oil we expect to receive from our customers as a pipeline loss allowance as part of the transportation of their crude oil. We subsequently sell this crude oil at market rates. We use derivative financial instruments to fix the sales price we will receive in the future for the sale of this crude oil. We elected not to designate these derivative financial instruments as cash flow hedges.

The operating and administrative expenses of our Liquids business increased $79.4 million for the year ended December 31, 2012 when compared with the same period in 2011 primarily due to the following:

• Increased workforce related costs and other allocated expenses of $28.2 million;

• Increased support costs of $16.0 million related to professional and regulatory expenses, maintenance, supplies and other outside services;

• Increased property tax expenses of $14.8 million; and

• Higher costs related to our integrity program of $11.2 million.

Over the past several years, Enbridge and the Partnership have focused on achieving pipeline industry leading performance in the areas of public and worker safety, operations and pipeline systems integrity. We have implemented initiatives such as our operational risk management plan, which puts emphasis on areas such as emergency response, pipeline integrity, pipeline control and leak detection systems as well as we have increased our internal inspection frequency and hired more personnel in field operations to ensure we meet this overriding objective. These efforts have increased our operating cost spending relative to prior years. For example, during 2012, we worked with an industry leading safety consultant to assist us with enhancing safety structure and processes. All of these programs and initiatives are essential to our long-term operations. We expect these costs to be an ongoing obligation to achieve and maintain best in class safety performance.

Environmental costs, net of recoveries, increased $21.6 million for the year ended December 31, 2012 when compared with the same period in 2011 of which $5.0 million, net of recoveries, is related to the Line 6B crude oil release. During the year ended December 31, 2012, we recognized $170.0 million in insurance recoveries in connection with the Line 6B crude oil release compared to $335.0 million for the same period in 2011. We increased our total incident cost accrual by $55.0 million for the year ended December 31, 2012, compared to an

increase of $215.0 million for the year ended December 31, 2011. Additional environmental costs and insurance recoveries are discussed below under Operating Impact of Lines 6A and 6B Crude Oil Releases. An additional $8.9 million of environmental costs were recognized related to the Line 14 crude oil release on our Lakehead system near Grand Marsh, Wisconsin that occurred on July 27, 2012. We also recognized additional environmental costs in aggregate of $7.7 million related to other minor crude oil releases.

For the year ended December 31, 2011, we settled a dispute with a shipper on our Lakehead crude oil pipeline system, which we recognized in 2011, for oil measurement adjustments we had previously experienced in prior years. We recorded $52.2 million to oil measurement adjustments, which is a reduction to operating expenses for the year ended December 31, 2011. There were no such adjustments for the year ended December 31, 2012.

Power costs increased $4.0 million for the year ended December 31, 2012, compared with the same period in 2011. The increase in power costs is primarily associated with the higher volumes of crude oil transported on our Lakehead system.

The increase in depreciation expense of $12.9 million for the year ended December 31, 2012 is directly attributable to the additional assets we have placed in service since the same period in 2011.

Operating Impact of Lines 6A and 6B Crude Oil Releases

We continue to perform necessary remediation, restoration and monitoring of the areas affected by the crude oil release from Line 6B of our Lakehead system. With respect to the Line 6B incident, we expect to make payments for additional costs associated with submerged oil and recovery operations, including remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. Primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, we have revised our total cost estimate to $820 million for the Line 6B incident, before insurance recoveries, for the year ended December 31, 2012, reflecting an increase of $55 million from our estimate at December 31, 2011. Our total cost estimate for the Line 6A crude oil release remains unchanged at approximately $48 million, before insurance recoveries and excluding additional fines and penalties. We continue to monitor this estimate to determine if our estimate should be updated. We have the potential of incurring additional costs in connection with these incidents including modified remediation requirements, other fines and penalties, as well as expenditures for litigation and settlement of claims. Our estimated costs for these incidents are based on currently available information and will be updated as considered necessary to incorporate material new information as it becomes available.

On July 2, 2012, we received a Notice of Probable Violation, or NOPV, from the PHMSA, related to the Line 6B crude oil release, which indicated a $3.7 million civil penalty that we paid during the third quarter of 2012. We have included the amount of the penalty in our total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012, the NTSB discussed the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012. We provided a reply to the NTSB on October 22, 2012 stating that we have either already or will soon be, fully implementing all of the NTSB recommendations.

On October 3, 2012, we received a letter from the EPA regarding a proposed order, which we refer to as the Proposed Order, for potential incremental containment and active recovery of submerged oil. We are in discussions with the EPA regarding the agency's intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. The nature and scope of any additional remediation activities that regulators may require is currently uncertain. Studies and additional technical evaluation by the EPA, the Partnership and other regulatory agencies may need to be completed before a final determination of any

additional remediation activities can be determined. We have accrued the estimated costs we deem likely to be incurred. However, when a final determination of the appropriate nature and scope of any additional remediation is made, it could result in significant cost being accrued.

The claims for the crude oil release for Lines 6B were covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. We have exceeded the limits of coverage under this insurance policy. We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.

Enbridge's current comprehensive insurance program, which became effective May 1, 2012 has a current liability aggregate limit of $660.0 million, including pollution liability, and will remain effective through April 30, 2013.

Year ended December 31, 2011 compared with year ended December 31, 2010

The operating revenue of our Liquids business increased for the year ended . . .